EXHIBIT 13.5
JERSEY CENTRAL POWER & LIGHT COMPANY
2002 ANNUAL REPORT TO STOCKHOLDERS
Jersey Central Power & Light Company (JCP&L) is a wholly owned electric
utility operating subsidiary of FirstEnergy Corp. It engages in the distribution
and sale of electric energy in an area of approximately 3,300 square miles in
New Jersey. It also engages in the sale, purchase and interchange of electric
energy with other electric companies. The area it serves has a population of
approximately 2.7 million.
In August 2000, FirstEnergy entered into an agreement to merge with GPU,
Inc., under which FirstEnergy would acquire all of the outstanding shares of
GPU, Inc.'s common stock for approximately $4.5 billion in cash and FirstEnergy
common stock. The merger became effective on November 7, 2001 and is being
accounted for by the purchase method. Prior to that time, Jersey Central Power &
Light Company was a wholly owned subsidiary of GPU, Inc.
Contents Page
- -------- ----
Selected Financial Data........................................... 1
Management's Discussion and Analysis.............................. 2-11
Consolidated Statements of Income................................. 12
Consolidated Balance Sheets....................................... 13
Consolidated Statements of Capitalization......................... 14
Consolidated Statements of Common Stockholder's Equity............ 15
Consolidated Statements of Preferred Stock........................ 15
Consolidated Statements of Cash Flows............................. 16
Consolidated Statements of Taxes.................................. 17
Notes to Consolidated Financial Statements........................ 18-30
Reports of Independent Accountants................................ 31-32
JERSEY CENTRAL POWER & LIGHT COMPANY
SELECTED FINANCIAL DATA
Nov. 7 - Jan. 1 -
2002 Dec. 31, 2001 Nov. 6, 2001 2000 1999 1998
- ----------------------------------------------------------------------------------------------------------------------
(Dollars in thousands)
Operating Revenues...................... $2,328,415 $ 282,902 | $1,838,638 $1,979,297 $2,018,209 $2,069,648
========== ========== | ========== ========== ========== ==========
|
Operating Income........................ $ 335,209 $ 43,666 | $ 292,847 $ 283,227 $ 277,420 $ 297,614
========== ========== | ========== ========== ========== ==========
|
Net Income ............................. $ 251,895 $ 30,041 | $ 34,467 $ 210,812 $ 172,380 $ 222,442
========== ========== | ========== ========== ========== ==========
|
Earnings on Common Stock................ $ 253,359 $ 29,343 | $ 29,920 $ 203,908 $ 162,862 $ 212,377
========== ========== | ========== ========== ========== ==========
|
Total Assets............................ $8,052,755 $8,039,998 | $6,009,054 $5,587,677 $4,382,073
========== ========== | ========== ========== ==========
|
|
Capitalization: |
Common Stockholder's Equity.......... $3,274,069 $3,163,701 | $1,459,260 $1,385,367 $1,557,073
Preferred Stock- |
Not Subject to Mandatory Redemption 12,649 12,649 | 12,649 12,649 37,741
Subject to Mandatory Redemption.... -- 44,868 | 51,500 73,167 86,500
Company-Obligated Mandatorily |
Redeemable Preferred Securities.... 125,244 125,250 | 125,000 125,000 125,000
Long-Term Debt....................... 1,210,446 1,224,001 | 1,093,987 1,133,760 1,173,532
---------- ---------- | ---------- ---------- ----------
Total Capitalization............... $4,622,408 $4,570,469 | $2,742,396 $2,729,943 $2,979,846
========== ========== | ========== ========== ==========
|
|
Capitalization Ratios: |
Common Stockholder's Equity.......... 70.8% 69.2%| 53.2% 50.7% 52.2%
Preferred Stock- |
Not Subject to Mandatory Redemption 0.3 0.3 | 0.5 0.5 1.3
Subject to Mandatory Redemption.... -- 1.0 | 1.9 2.7 2.9
Company-Obligated Mandatorily |
Redeemable Preferred Securities.... 2.7 2.7 | 4.5 4.6 4.2
Long-Term Debt....................... 26.2 26.8 | 39.9 41.5 39.4
----- ----- | ----- ----- -----
Total Capitalization............... 100.0% 100.0%| 100.0% 100.0% 100.0%
===== ===== | ===== ===== =====
|
|
Transmission and Distribution |
Kilowatt-Hour Deliveries (Millions): |
Residential.......................... 8,976 1,428 | 7,042 8,087 7,978 7,551
Commercial........................... 8,509 1,330 | 6,787 7,706 7,624 7,259
Industrial........................... 3,171 474 | 2,670 3,307 3,289 3,474
Other................................ 81 17 | 66 82 81 81
------ ------- | ------ ------ ------ ------
Total Retail......................... 20,737 3,249 | 16,565 19,182 18,972 18,365
Total Wholesale...................... 5,039 295 | 1,780 2,161 1,622 1,690
------ ------- | ------ ------ ------ ------
Total................................ 25,776 3,544 | 18,345 21,343 20,594 20,055
====== ======= | ====== ====== ====== ======
|
|
Customers Served: |
Residential.......................... 921,716 909,494 | 896,629 883,930 872,134
Commercial........................... 112,385 109,985 | 107,479 107,210 105,611
Industrial........................... 2,759 2,785 | 2,835 2,965 3,014
Other................................ 1,393 1,484 | 1,551 1,648 1,635
--------- --------- | --------- ------- -------
Total................................ 1,038,253 1,023,748 | 1,008,494 995,753 982,394
========= ========= | ========= ======= =======
1
JERSEY CENTRAL POWER & LIGHT COMPANY
Management's Discussion and Analysis of
Results of Operations and Financial Condition
This discussion includes forward-looking statements based on information
currently available to management that is subject to certain risks and
uncertainties. Such statements typically contain, but are not limited to, the
terms anticipate, potential, expect, believe, estimate and similar words. Actual
results may differ materially due to the speed and nature of increased
competition and deregulation in the electric utility industry, economic or
weather conditions affecting future sales and margins, changes in markets for
energy services, changing energy market prices, legislative and regulatory
changes (including revised environmental requirements), and the availability and
cost of capital.
Results of Operations
In 2002, earnings on common stock increased to $253.4 million, from
$59.3 million in 2001, due to higher operating revenues and the absence of a
2001 after-tax charge of $177.5 million, which reduced deferred costs in
accordance with the Stipulation of Settlement related to the merger of
FirstEnergy and GPU, Inc. Partially offsetting these favorable results were
increased purchased power costs. In 2001, earnings on common stock decreased by
70.9% to $59.3 million, from $203.9 million in 2000. Results in 2001 were
negatively impacted by the $177.5 after-tax charge previously discussed, and by
higher purchased power costs. Partially offsetting these factors were lower
other operating costs, and the absence of nuclear operating costs in 2001, as
well as increases in operating revenues.
Operating revenues increased $206.9 million in 2002, following a $142.2
million increase in 2001. The sources of the changes in operating revenues
during 2002 and 2001, as compared to the prior year, are summarized in the
following table.
Sources of Revenue Changes 2002 2001
-------------------------------------------------------------------------
Increase (Decrease) (In millions)
Increase in kilowatt-hour sales due to level of
retail-customers shopping for generation service... $ 34.4 $ 67.3
Increase in other retail kilowatt-hour sales......... 98.2 38.4
Increase in wholesale sales.......................... 74.1 44.1
All other changes.................................... 0.2 (7.6)
-------------------------------------------------------------------------
Net Increase in Operating Revenues................... $206.9 $142.2
=========================================================================
Electric Sales
In 2002, further reductions in the number of customers who received
their power from alternate suppliers, and therefore returned to us as full
service customers, continued to have a positive effect on operating revenues.
During 2002, only 0.7% of kilowatt-hours delivered were to shopping customers,
whereas that percentage was 4.5% in 2001 and 11.7% in 2000. In addition to the
higher revenues from returning shopping customers, warmer summer weather in both
2002 and 2001 contributed to significant increases in retail sales. This was
partially offset by a decrease in kilowatt-hour sales to industrial customers,
due to a decline in economic conditions during 2002.
On August 1, 2002, the obligation to provide power to customers not
choosing to receive power from an alternative energy supplier, referred to as
Basic Generation Service (BGS), was transferred from us to external parties
through an auction process authorized by the New Jersey Board of Public
Utilities (NJBPU). Therefore, we began selling all of our self-supplied energy
(non-utility generation and owned generation) into the wholesale market. This
contributed to a significant increase in kilowatt-hour sales to wholesale
customers during 2002; however, that increase was partially offset by lower
average prices for energy in 2002, compared to 2001. Less kilowatt-hour sales
were sold to wholesale customers in 2001; however, revenues increased due to
higher average prices for energy sold compared to 2000 prices.
2
Changes in kilowatt-hour sales by customer class in 2002 and 2001 are
summarized in the following table:
Changes in Kilowatt-hour Sales 2002 2001
--------------------------------------------------
Increase (Decrease)
Residential.................. 7.0% 4.7%
Commercial................... 3.4% 5.3%
Industrial................... (0.7)% (4.9)%
--------------------------------------------------
Total Retail................. 4.3% 3.3%
Wholesale.................... 142.8% (4.0)%
--------------------------------------------------
Total Sales.................. 17.4% 2.6%
--------------------------------------------------
Operating Expenses and Taxes
Total operating expenses and taxes increased $208.2 million in 2002,
after increasing $89.0 million in 2001, compared to the preceding year. In both
periods, higher purchased power costs accounted for the majority of the
increase. In 2002, the increase was offset in part by lower general taxes, due
principally to a reduction in the New Jersey transitional energy facilities
assessment during the second quarter of 2002. In 2001, the increase in purchased
power costs was partially offset by lower other operating costs, due to reduced
bad debt expense and employee benefit costs, and decreased nuclear operating
costs. With the sale of the Oyster Creek Nuclear Generating Station in August
2000, we no longer have any nuclear operating costs, which were $78.5 million in
2000. However, as a result of the sale and higher customer demand in 2002 and
2001, we have been required to purchase more power.
In 2002, fuel and purchased power costs increased $179.6 million,
compared to 2001. The increase was due primarily to more power being purchased
through two-party agreements and from associated companies during 2002. The
increase was partially offset by a decrease in power purchased through the PJM
Power Pool, and the absence of non-utility generation contract buyout costs
recognized in 2001. Fuel and purchased power costs increased $177.6 million in
2001, compared to 2000. That increase was primarily attributed to greater
quantities of power purchased through both two-party agreements and through the
PJM Power Pool. Also contributing to the increase was a higher average cost of
two-party power purchases in 2001 than in 2000. These increases were partially
offset by lower fuel costs due to the sale of Oyster Creek.
Other Income
Other income increased $183.3 million in 2002, after decreasing $199.8
million in 2001, compared to the prior year. The change in both periods was due
primarily to a 2001 charge of $300 million ($177.5 million net of tax) to reduce
deferred costs in accordance with the Stipulation of Settlement related to the
merger between FirstEnergy and GPU.
Net Interest Charges
In 2002, net interest charges decreased $5.3 million, compared to 2001,
due primarily to reduced short-term borrowing levels and the amortization of
fair value adjustments recognized in connection with the merger. These
reductions were partially offset by a decrease in deferred interest costs. In
addition, we issued $320 million of transition bonds through a special purpose
finance subsidiary in 2002 (see Note 4F) and $150 million of notes in 2001, and
redeemed $192 million of notes in 2002 and $40 million of notes in 2001. These
transactions collectively had a minimal net effect on interest charges in 2002.
In 2001, net interest charges decreased $0.2 million, compared to the prior
year, with the slight decrease due to an increase in deferred interest costs,
offset by interest expense on the senior notes issued in 2001 and higher average
short-term debt levels.
Preferred Stock Dividend Requirements
In the third quarter of 2002, we realized a $3.6 million non-cash gain
on the reacquisition of $29.8 million of preferred stock. Preferred stock
dividend requirements decreased $3.1 million in 2002, and $1.7 million in 2001,
compared to the prior year, due to the 2002 reacquisition and redemptions of
cumulative preferred stock pursuant to mandatory and optional sinking fund
provisions during 2002 and 2001.
3
Capital Resources and Liquidity
Changes in Cash Position
As of December 31, 2002, we had $4.8 million of cash and cash
equivalents compared with $31.4 million as of December 31, 2001. The major
sources for changes in these balances are summarized below.
Cash Flows From Operating Activities
Cash flows provided from operating activities totaled $309.0 million in
2002 and $289.8 million in 2001. The sources of these changes are as follows:
Operating Cash Flows 2002 2001
----------------------------------------------------------
(in millions)
Cash earnings (1).................. $325 $219
Working capital and other.......... (16) 71
----------------------------------------------------------
Total..................... $309 $290
==========================================================
(1) Includes net income, depreciation and amortization, deferred costs
recoverable as regulatory assets, deferred income taxes, and
and investment tax credits.
Cash Flows From Financing Activities
In 2002, net cash used for financing activities of $140.4 million
reflects redemptions of debt and preferred stock, as well as $190.7 million in
common dividend payments to FirstEnergy, offset in part by proceeds from the
issuance of transition bonds. The following table provides details regarding new
issues and redemptions during 2002:
Securities Issued or Redeemed in 2002
-------------------------------------------------------------
(in millions)
New Issues
Transition Bonds (See Note 4)............... $320
-------------------------------------------------------------
Redemptions
First Mortgage Bonds........................ 192
Preferred Stock............................. 52
Other....................................... 4
-------------------------------------------------------------
Total Redemptions....................... 248
Short-term Borrowings, net use of cash........... 18
-------------------------------------------------------------
We had no short-term indebtedness on December 31, 2002, compared to
$18.1 million on December 31, 2001. We may borrow from our affiliates on a
short-term basis. We will not issue first mortgage bonds (FMBs) other than as
collateral for senior notes, since our senior note indentures prohibit (subject
to certain exceptions) us from issuing any debt which is senior to the senior
notes. As of December 31, 2002, we had the capability to issue $393 million of
additional senior notes based upon FMB collateral. At year-end 2002, based upon
applicable earnings coverage tests and our charter, we could issue $1.2 billion
of preferred stock (assuming no additional debt was issued).
At the end of 2002, our common equity as a percentage of capitalization
stood at 71%, as compared to 69% and 53% at the end of 2001 and 2000,
respectively. In 2001, we experienced a significant increase in this ratio due
to the allocation of the purchase price when we were acquired by FirstEnergy.
Cash Flows From Investing Activities
In 2002, cash used in investing activities totaled $195.2 million,
principally for property additions to support the distribution of electricity
and loans to associated companies. In 2001, $167.0 million of cash was used in
investing activities, principally for property additions.
Our cash requirements in 2003 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without increasing our net debt and preferred stock
outstanding. Over the next three years, we expect to meet our contractual
obligations with cash from operations. Thereafter, we expect to use a
combination of cash from operations and funds from the capital markets.
4
Less than 1-3 3-5 More than
Contractual Obligations Total 1 Year Years Years 5 Years
- ------------------------------------------------------------------------------
(in millions)
Long-term debt......... $1,374 $174 $ 243 $ 267 $ 690
Preferred stock (1).... 125 -- -- -- 125
Operating leases....... 66 3 3 3 57
Purchases (2).......... 4,159 528 943 953 1,735
- ---------------------------------------------------------------------------
Total............... $5,724 $705 $1,189 $1,223 $2,607
- ---------------------------------------------------------------------------
(1) Subject to mandatory redemption
(2) Fuel and power purchases under contracts with fixed or minimum quantities
and approximate timing
Our capital spending for the period 2003 through 2007 is expected to be
about $462 million, of which approximately $102 million applies to 2003.
Following approval of the merger of FirstEnergy and GPU by the NJBPU on
September 26, 2001, Standard and Poor's adjusted our corporate credit rating
from A/A1 to BBB/A-2, our senior secured debt rating from A+ to BBB+ and our
preferred stock rating from BBB+ to BB+. The credit rating outlook of both
Standard & Poor's and Moody's is stable.
On February 22, 2002, Moody's Investor Service changed its credit rating
outlook for FirstEnergy from stable to negative. The change was based upon a
decision by the Commonwealth Court of Pennsylvania to remand to the Pennsylvania
Public Utility Commission (PPUC) for reconsideration of its decision on the
mechanism for sharing merger savings and reversed the PPUC decisions regarding
rate relief and accounting deferrals rendered in connection with its approval of
the GPU merger. On April 4, 2002, Standard & Poor's (S&P) changed its outlook
for FirstEnergy's credit ratings from stable to negative citing recent
developments including: damage to the Davis-Besse reactor vessel head (we have
no ownership interest in Davis-Besse), the Pennsylvania Commonwealth Court
decision, and deteriorating market conditions for some sales of FirstEnergy's
remaining non-core assets. On July 31, 2002, Fitch revised its rating outlook
for FirstEnergy securities to negative from stable. The revised outlook
reflected the adverse impact of the unplanned Davis-Besse outage, Fitch's
judgment about NRG's financial ability to consummate the purchase of four power
plants from FirstEnergy and Fitch's expectation of subsequent delays in debt
reduction. On August 1, 2002, S&P concluded that while NRG's liquidity position
added uncertainty to FirstEnergy's sale of power plants to NRG, FirstEnergy's
ratings would not be affected. S&P found its cash flows sufficiently stable to
support a continued (although delayed) program of debt and preferred stock
redemption. S&P noted that it would continue to closely monitor our progress on
various initiatives. On January 21, 2003, S&P indicated its concern about
FirstEnergy's disclosure of non-cash charges related to deferred costs in
Pennsylvania, pension and other post-retirement benefits, and Emdersa
(FirstEnergy's Argentina operations), which were higher than anticipated in the
third quarter of 2002. S&P identified the restart of the Davis-Besse nuclear
plant "...without significant delay beyond April 2003..." as key to maintaining
its current debt ratings. S&P also identified other issues it would continue to
monitor including: FirstEnergy's deleveraging efforts, free cash generated
during 2003, the Jersey Central Power & Light Company rate case, successful
hedging of our short power position, and continued capture of projected merger
savings. While FirstEnergy anticipates being prepared to restart the Davis-Besse
plant in the spring of 2003, the Nuclear Regulatory Commission (NRC) must
authorize the unit's restart following a formal inspection process prior to
FirstEnergy's returning the unit to service. Significant delays in the planned
date of Davis-Besse's return to service or other factors (identified above)
affecting the speed with which FirstEnergy reduces debt could put additional
pressure on JCP&L's credit ratings.
Market Risk Information
We use various market risk sensitive instruments, including derivative
contracts, primarily to manage the risk of price fluctuations. Our Risk Policy
Committee, comprised of FirstEnergy executive officers, exercises an independent
risk oversight function to ensure compliance with corporate risk management
policies and prudent risk management practices.
Commodity Price Risk
We are exposed to market risk primarily due to fluctuations in
electricity and natural gas prices. To manage the volatility relating to these
exposures, we use a variety of non-derivative and derivative instruments,
including forward contracts, options and futures contracts. The derivatives are
used for hedging purposes. Most of our non-hedge derivative contracts represent
non-trading positions that do not qualify for hedge treatment under Statement of
Financial Accounting Standards (SFAS) 133. The change in the fair value of
commodity derivative contracts related to energy production during 2002 is
summarized in the following table:
5
Increase (Decrease) in the Fair Value of Commodity Derivative Contracts
Non-Hedge Hedge Total
--------- ----- -----
(In millions)
Change in the Fair Value of Commodity Derivative Contracts
Outstanding net asset as of January 1, 2002...................... $ 1.1 $ 0.4 $1.5
New contract value when entered.................................. -- 2.1 2.1
Additions/Change in value of existing contracts.................. 7.6 (2.3) 5.3
Settled contracts................................................ -- (0.3) (0.3)
--------------------------
Net Assets - Derivatives Contracts as of December 31, 2002 (1)... $ 8.7 $(0.1) $8.6
==========================
Impact of Changes in Commodity Derivative Contracts (2)
Balance Sheet Effects:
Other Comprehensive Income (Pre-Tax).......................... $ -- $(2.6) $2.6)
Regulatory Liability.......................................... $ 7.6 $ -- $7.6
(1) Includes $8.6 million in non-hedge commodity derivative contracts which are
offset by a regulatory liability.
(2) Represents the increase in value of existing contracts and settled
contracts.
Non-Hedge Hedge Total
--------- ----- -----
(In millions)
Current-
Other Liabilities............... $ -- $(0.1) $(0.1)
Non-Current-
Other Deferred Charges.......... 8.7 -- 8.7
---- ---- -----
Net assets.................... $8.7 $(0.1) $ 8.6
==== ====== =====
Derivatives included on the Consolidated Balance Sheet as of December 31, 2002:
The valuation of derivative contracts is based on observable market
information to the extent that such information is available. In cases where
such information is not available, we rely on model-based information. The model
provides estimates of future regional prices for electricity and an estimate of
related price volatility. We use these results to develop estimates of fair
value for financial reporting purposes and for internal management decision
making. Sources of information for the valuation of derivative contracts by year
are summarized in the following table:
Source of Information - Fair Value by Contract Year
- ---------------------------------------------------
2003 2004 2005 2006 Thereafter Total
---- ---- ---- ---- ---------- -----
(In millions)
Prices based on external sources(1)... $0.2 $0.3 $0.7 $ -- $ -- $1.2
Prices based on models................ -- -- -- 1.1 6.3 7.4
---------------------------------------
Total(2).......................... $0.2 $0.3 $0.7 $1.1 $6.3 $8.6
=======================================
(1) Broker quote sheets.
(2) Includes $8.6 million from an embedded option that is offset by a regulatory
liability and does not affect earnings.
We perform sensitivity analyses to estimate our exposure to the market
risk of our commodity position. A hypothetical 10% adverse shift in quoted
market prices in the near term on derivative instruments would not have had a
material effect on our consolidated financial position or cash flows as of
December 31, 2002.
Interest Rate Risk
- ------------------
Our exposure to fluctuations in market interest rates is reduced since
our debt has fixed interest rates, as noted in the following table.
6
Comparison of Carrying Value to Fair Value
- ----------------------------------------------------------------------------------------------------------------
There- Fair
2003 2004 2005 2006 2007 after Total Value
- ----------------------------------------------------------------------------------------------------------------
(Dollars in millions)
Assets
- ----------------------------------------------------------------------------------------------------------------
Investments other than Cash
and Cash
Equivalents-Fixed Income.... -- -- -- -- -- $224 $ 224 $ 224
Average interest rate....... 5.0% 5.0%
- ----------------------------------------------------------------------------------------------------------------
- ----------------------------------------------------------------------------------------------------------------
Liabilities
- ----------------------------------------------------------------------------------------------------------------
Long-term Debt:
Fixed rate..................... $174 $176 $67 $231 $36 $690 $1,374 $1,415
Average interest rate ...... 6.1% 6.9% 6.1% 6.5% 6.1% 7.0% 6.7%
- ----------------------------------------------------------------------------------------------------------------
Preferred Stock................ -- -- -- -- -- $125 $ 125 $ 127
Average dividend rate ...... 8.6% 8.6%
- ----------------------------------------------------------------------------------------------------------------
We are subject to the inherent interest rate risks related to
refinancing maturing debt by issuing new debt securities. Changes in the market
value of our nuclear decommissioning trust funds are recognized by making
corresponding changes to the decommissioning liability, as described in Note 1
to the consolidated financial statements.
Equity Price Risk
- -----------------
Included in nuclear decommissioning trusts are marketable equity
securities carried at their market value of approximately $52 million and $65
million at December 31, 2002 and 2001, respectively. A hypothetical 10% decrease
in prices quoted by stock exchanges would result in a $5 million reduction in
fair value as of December 31, 2002. (See Note 1 - "Supplemental Cash Flows
Information.")
Outlook
Our industry continues to transition to a more competitive environment.
Beginning in late 1999, all of our customers could select alternative energy
suppliers. We continue to deliver power to homes and businesses through our
existing distribution system, which remains regulated. To support customer
choice, rates were restructured into unbundled service charges and additional
non-bypassable charges to recover stranded costs (confirmed by a NJBPU Final
Decision and Order issued in March 2001). On August 1, 2002, the obligation to
provide power to those customers not choosing to receive power from an
alternative energy supplier, referred to as BGS, was transferred from us to
external parties through an auction process authorized by the NJBPU.
Regulatory assets are costs which regulatory agencies have authorized
for recovery from customers in future periods and, without such authorization,
would have been charged to income when incurred. All of our regulatory assets
are expected to continue to be recovered under the provisions of the regulatory
plans as discussed below. Our regulatory assets totaled $3.2 billion and $3.3
billion as of December 31, 2002 and 2001, respectively.
Regulatory Matters
Under New Jersey transition legislation, all electric distribution
companies were required to file rate cases to determine the level of unbundled
rate components to become effective August 1, 2003. On August 1, 2002, we
submitted two rate filings with the NJBPU. The first filing requested increases
in base electric rates of approximately $98 million annually. The second filing
was a request to recover deferred costs that exceeded amounts being recovered
under the current market transition charge and societal benefits charge rates;
one proposed method of recovery of these costs is the securitization of the
deferred balance as further discussed below. This securitization methodology is
similar to the Oyster Creek securitization discussed below. Hearings began in
February 2003. The Administrative Law Judge's recommended decision is due in
June 2003 and the NJBPU's subsequent decision is due in July 2003.
Our regulatory plan provided for the ability to securitize stranded
costs associated with the divested Oyster Creek Nuclear Generating Station. A
February 2002 NJBPU order authorized us to issue $320 million of transition
bonds to securitize the recovery of these costs and provided for a usage-based
non-bypassable transition bond charge and for the transfer of the bondable
transition property to another entity. We sold $320 million of transition bonds
through a wholly owned subsidiary, JCP&L Transition Funding LLC, in June 2002 --
that debt is recognized on the Consolidated Balance Sheet (see Note 4). We are
permitted to defer for future collection from customers the amounts by which our
costs of supplying BGS to non-shopping customers and costs incurred under
non-utility generation agreements exceed amounts collected through BGS and
market transition charge rates. As of December 31, 2002, the accumulated
deferred cost balance totaled approximately $549 million. The NJBPU also allowed
securitization of our deferred balance to the extent permitted by law upon our
application and a determination by the NJBPU that the conditions of the New
Jersey restructuring legislation are met.
7
In December 2001, the NJBPU authorized the auctioning of BGS for the
period from August 1, 2002 through July 31, 2003 to meet the electricity demands
of all customers who have not selected an alternative supplier. The results of
the February 2002 auction, with the NJBPU's approval, removed our BGS obligation
of 5,100 MW for the period August 1, 2002 through July 31, 2003. In February
2003, the auctioning of BGS for the period beginning August 1, 2003 took place.
The auction covered a fixed price bid (applicable to all residential and smaller
commercial and industrial customers) and an hourly price bid (applicable to all
large industrial customers) process. We will sell all self-supplied energy
(non-utility generation and owned generation) into the wholesale market, which
will offset our deferred energy cost balance.
As part of the restructuring orders, we were obligated, through July 31,
2002, to supply electricity to customers who do not choose an alternate
supplier. The total forecasted peak of this obligation in 2002 was 5,400 MW. The
successful BGS auction in New Jersey removed that BGS obligation for the period
from August 1, 2002 to July 31, 2003.
FERC Regulatory Matters
On December 19, 2002 the Federal Energy Regulatory Commission (FERC)
granted unconditional Regional Transmission Organization status to PJM
Interconnection, LLC (PJM). We are a transmission owner in PJM.
Environmental Matters
We have been named as a "potentially responsible party" (PRP) at waste
disposal sites which may require cleanup under the Comprehensive Environmental
Response, Compensation and Liability Act of 1980. Allegations of disposal of
hazardous substances at historical sites and the liability involved are often
unsubstantiated and subject to dispute; however, federal law provides that all
PRPs for a particular site be held liable on a joint and several basis.
Therefore, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of December 31, 2002, based on estimates of the
total costs of cleanup, our proportionate responsibility for such costs and the
financial ability of other nonaffiliated entities to pay. In addition, we have
accrued liabilities for environmental remediation of former manufactured gas
plants in New Jersey; those costs are being recovered through a non-bypassable
societal benefits charge. We have accrued liabilities aggregating approximately
$47.1 million as of December 31, 2002. We do not believe environmental
remediation costs will have a material adverse effect on our financial
condition, cash flows or results of operations.
Legal Matters
Various lawsuits, claims and proceedings related to our normal business
operations are pending against us, the most significant of which are described
below.
We have a 25% ownership interest in Unit 2 of the Three Mile Island
Nuclear Plant (TMI-2), which was damaged during a 1979 accident. As a result of
the accident, claims for alleged personal injury against us, Metropolitan Edison
Company, Pennsylvania Electric Company and GPU (the defendants) had been filed
in the U.S. District Court for the Middle District of Pennsylvania. In 1996, the
District Court granted a motion for summary judgment filed by the defendants and
dismissed the ten initial "test cases" which had been selected for a test case
trial. In January 2002, the District Court granted our motion for summary
judgment on the remaining 2,100 pending claims. In February 2002, the plaintiffs
filed a notice of appeal of this decision (see Note 6 - Other Legal
Proceedings). In December 2002, the Court of Appeals for the Third Circuit
refused to hear the appeal which effectively ended further legal action for
those claims.
In July 1999, the Mid-Atlantic states experienced a severe heat storm
which resulted in power outages throughout the service territories of many
electric utilities, including JCP&L. In an investigation into the causes of the
outages and the reliability of the transmission and distribution systems of all
four New Jersey electric utilities, the NJBPU concluded that there was not a
prima facie case demonstrating that, overall, we provided unsafe, inadequate or
improper service to our customers. In July 1999, two class action lawsuits
(subsequently consolidated into a single proceeding) were filed in New Jersey
Superior Court against JCP&L and other GPU companies, seeking compensatory and
punitive damages arising from the July 1999 service interruptions in our service
territory. In May 2001, the court denied without prejudice our motion seeking
decertification of the class. Discovery continues in the class action, but no
trial date has been set. In October 2001, the court held argument on the
plaintiffs' motion for partial summary judgment, which contends that we are
bound to several findings of the NJBPU investigation. The plaintiffs' motion was
denied by the Court in November 2001 and the plaintiffs' motion to file an
appeal of this decision was denied by the New Jersey Appellate Division. We have
also filed a motion for partial summary judgment that is currently pending
before the Superior Court. We are unable to predict the outcome of these
matters.
8
Significant Accounting Policies
We prepare our consolidated financial statements in accordance with
accounting principles that are generally accepted in the United States.
Application of these principles often requires a high degree of judgment,
estimates and assumptions that affect financial results. All of our assets are
subject to their own specific risks and uncertainties and are regularly reviewed
for impairment. Assets related to the application of the policies discussed
below are similarly reviewed with their risks and uncertainties reflecting these
specific factors. Our more significant accounting policies are described below.
Purchase Accounting
On November 7, 2001, the merger between FirstEnergy and GPU became
effective, and we became a wholly owned subsidiary of FirstEnergy. The merger
was accounted for by the purchase method of accounting, which requires judgment
regarding the allocation of the purchase price based on the fair values of the
assets acquired (including intangible assets) and the liabilities assumed. The
fair values of the acquired assets and assumed liabilities were based primarily
on estimates. The adjustments reflected in our records, which were finalized in
the fourth quarter of 2002, primarily consist of: (1) revaluation of certain
property, plant and equipment; (2) adjusting preferred stock subject to
mandatory redemption and long-term debt to estimated fair value; (3) recognizing
additional obligations related to retirement benefits; and (4) recognizing
estimated severance and other compensation liabilities. The excess of the
purchase price over the estimated fair values of the assets acquired and
liabilities assumed was recognized as goodwill. Based on the guidance provided
by SFAS 142, "Goodwill and Other Intangible Assets," we evaluate our goodwill
for impairment at least annually and would make such an evaluation more
frequently if indicators of impairment should arise. The forecasts used in our
evaluations of goodwill reflect operations consistent with our general business
assumptions. Unanticipated changes in those assumptions could have a significant
effect on our future evaluations of goodwill. As of December 31, 2002, we had
recorded goodwill of approximately $2.0 billion related to the merger.
Regulatory Accounting
We are subject to regulation that sets the prices (rates) we are
permitted to charge our customers based on costs that the regulatory agencies
determine we are permitted to recover. At times, regulators permit the future
recovery through rates of costs that would be currently charged to expense by an
unregulated company. This rate-making process results in the recording of
regulatory assets based on anticipated future cash inflows. As a result of the
changing regulatory framework in New Jersey, a significant amount of regulatory
assets have been recorded - $3.2 billion as of December 31, 2002. We regularly
review these assets to assess their ultimate recoverability within the approved
regulatory guidelines. Impairment risk associated with these assets relates to
potentially adverse legislative, judicial or regulatory actions in the future.
Derivative Accounting
Determination of appropriate accounting for derivative transactions
requires the involvement of management representing operations, finance and risk
assessment. In order to determine the appropriate accounting for derivative
transactions, the provisions of the contract need to be carefully assessed in
accordance with the authoritative accounting literature and management's
intended use of the derivative. New authoritative guidance continues to shape
the application of derivative accounting. Management's expectations and
intentions are key factors in determining the appropriate accounting for a
derivative transaction and, as a result, such expectations and intentions are
documented. Derivative contracts that are determined to fall within the scope of
SFAS 133, as amended, must be recorded at their fair value. Active market prices
are not always available to determine the fair value of the later years of a
contract, requiring that various assumptions and estimates be used in their
valuation. We continually monitor our derivative contracts to determine if our
activities, expectations, intentions, assumptions and estimates remain valid. As
part of our normal operations, we enter into commodity contracts which increase
the impact of derivative accounting judgments.
Revenue Recognition
We follow the accrual method of accounting for revenues, recognizing
revenue for kilowatt-hours that have been delivered but not yet billed through
the end of the accounting period. The determination of unbilled revenues
requires management to make various estimates including:
o Net energy generated or purchased for retail load
o Losses of energy over transmission and distribution lines
o Mix of kilowatt-hour usage by residential, commercial and industrial
customers
o Kilowatt-hour usage of customers receiving electricity from
alternative suppliers
9
Pension and Other Postretirement Benefits Accounting
Our reported costs of providing non-contributory defined pension
benefits and postemployment benefits other than pensions (OPEB) are dependent
upon numerous factors resulting from actual plan experience and certain
assumptions.
Pension and OPEB costs are affected by employee demographics (including
age, compensation levels, and employment periods), the level of contributions we
make to the plans, and earnings on plan assets. Pension and OPEB costs may also
be affected by changes to key assumptions, including anticipated rates of return
on plan assets, the discount rates and health care trend rates used in
determining the projected benefit obligations and pension and OPEB costs.
In accordance with SFAS 87, "Employers' Accounting for Pensions" and
SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," changes in pension and OPEB obligations associated with these factors
may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.
In selecting an assumed discount rate, we consider currently available
rates of return on high-quality fixed income investments expected to be
available during the period to maturity of the pension and other postretirement
benefit obligations. Due to the significant decline in corporate bond yields and
interest rates in general during 2002, we reduced the assumed discount rate as
of December 31, 2002 to 6.75% from 7.25% used in 2001.
Our assumed rate of return on pension plan assets considers historical
market returns and economic forecasts for the types of investments held by our
pension trusts. The market values of our pension assets have been affected by
sharp declines in the equity markets since mid-2000. In 2002, plan assets have
earned (11.3)%. Our pension costs in 2002 were computed assuming a 10.25% rate
of return on plan assets. As of December 31, 2002 the assumed return on plan
assets was reduced to 9.00% based upon our projection of future returns and
pension trust investment allocation of approximately 60% large cap equities, 10%
small cap equities and 30% bonds.
Based on pension assumptions and pension plan assets as of December 31,
2002, we will not be required to fund our pension plans in 2003. While OPEB plan
assets have also been affected by sharp declines in the equity market, the
impact is not as significant due to the relative size of the plan assets.
However, health care cost trends have significantly increased and will affect
future OPEB costs. The 2003 composite health care trend rate assumption is
approximately 10%-12% gradually decreasing to 5% in later years, compared to our
2002 assumption of approximately 10% in 2002, gradually decreasing to 4%-6% in
later years. In determining our trend rate assumptions, we included the specific
provisions of our health care plans, the demographics and utilization rates of
plan participants, actual cost increases experienced in our health care plans,
and projections of future medical trend rates. Our non-cash, pre-tax pension and
OPEB expense under SFAS 87 and SFAS 106 is expected to increase by $29 million
and $10 million, respectively - a total of $39 million in 2003 as compared to
2002.
Increase in Costs from Adverse Changes in Key Assumptions
- -----------------------------------------------------------------------------
Assumption Adverse Change Pension OPEB Total
- -----------------------------------------------------------------------------
(In millions)
Discount rate................ Decrease by 0.25% $2.5 $1.3 $3.8
Long-term return on assets... Decrease by 0.25% $1.7 $0.5 $2.2
Health care trend rate....... Increase by 1% na $3.7 $3.7
Long-Lived Assets
In accordance with SFAS 144, "Accounting for the Impairment or Disposal
of Long-Lived Assets," we periodically evaluate our long-lived assets to
determine whether conditions exist that would indicate that the carrying value
of an asset may not be fully recoverable. The accounting standard requires that
if the sum of future cash flows (undiscounted) expected to result from an asset
is less than the carrying value of the asset, an asset impairment must be
recognized in the financial statements. If impairment were to occur, other than
of a temporary nature, we would recognize a loss - calculated as the difference
between the carrying value and the estimated fair value of the asset (discounted
future net cash flows).
10
Recently Issued Accounting Standards Not Yet Implemented
- --------------------------------------------------------
SFAS 143, "Accounting for Asset Retirement Obligations"
In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement
Obligations". The new statement provides accounting standards for retirement
obligations associated with tangible long-lived assets, with adoption required
by January 1, 2003. SFAS 143 requires that the fair value of a liability for an
asset retirement obligation be recorded in the period in which it is incurred.
The associated asset retirement costs are capitalized as part of the carrying
amount of the long-lived asset. Over time the capitalized costs are depreciated
and the present value of the asset retirement liability increases, resulting in
a period expense. However, rate-regulated entities may recognize regulatory
assets or liabilities if the criteria for such treatment are met. Upon
retirement, a gain or loss would be recorded if the cost to settle the
retirement obligation differs from the carrying amount.
We have identified applicable legal obligations as defined under the new
standard, principally for nuclear power plant decommissioning. Upon adoption of
SFAS 143 in January 2003, asset retirement costs of $98 million were recorded as
part of the carrying amount of the related long-lived asset, offset by
accumulated depreciation of $98 million. The asset retirement liability at the
date of adoption was $104 million. As of December 31, 2002, we had recorded
decommissioning liabilities of $130 million. The change in the estimated
liabilities resulted from changes in methodology and various assumptions,
including changes in the projected dates for decommissioning.
Management expects that substantially all of our nuclear decommissioning
costs will be recoverable through regulated rates. Therefore, we recognized a
regulatory liability of $26 million upon adoption of SFAS 143 for the transition
amounts related to establishing the asset retirement obligations for nuclear
decommissioning.
SFAS 146, "Accounting for Costs Associated with Exit or Disposal
Activities"
This statement, which was issued by the FASB in July 2002, requires the
recognition of costs associated with exit or disposal activities at the time
they are incurred rather than when management commits to a plan of exit or
disposal. It also requires the use of fair value for the measurement of such
liabilities. The new standard supersedes guidance provided by Emerging Issues
Task Force Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring)." This new standard was effective for exit
and disposal activities initiated after December 31, 2002. Since it is applied
prospectively, there will be no impact upon adoption. However, SFAS 146 could
change the timing and amount of costs recognized in connection with future exit
or disposal activities.
FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others - an interpretation of FASB Statements No. 5, 57,
and 107 and rescission of FASB Interpretation No. 34"
The FASB issued FIN 45 in January 2003. This interpretation identifies
minimum guarantee disclosures required for annual periods ending after December
15, 2002. It also clarifies that providers of guarantees must record the fair
value of those guarantees at their inception. This accounting guidance is
applicable on a prospective basis to guarantees issued or modified after
December 31, 2002. We do not believe that implementation of FIN 45 will be
material but we will continue to evaluate anticipated guarantees.
FIN 46, "Consolidation of Variable Interest Entities - an interpretation
of ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This Interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions in the first interim or
annual reporting period beginning after June 15, 2003 (our third quarter of
2003). The FASB also identified transitional disclosure provisions for all
financial statements issued after January 31, 2003.
We currently have transactions with entities in connection with the sale
of preferred securities and debt secured by bondable property, and which are
reasonably possible of meeting within the scope of this interpretation, and
which may meet the definition of a VIE in accordance with FIN 46. We currently
consolidate those entities and believe we will continue to consolidate following
the adoption of FIN 46.
11
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME
Nov 7 - Jan. 1 -
2002 Dec. 31, 2001 Nov. 6, 2001 2000
- ----------------------------------------------------------------------------------------------------------------------
(In thousands)
OPERATING REVENUES........................................ $2,328,415 $282,902 | $1,838,638 $1,979,297
---------- -------- | ---------- ----------
|
OPERATING EXPENSES AND TAXES: |
Fuel and purchased power............................... 1,248,012 136,123 | 932,300 890,812
Nuclear operating costs................................ -- -- | -- 78,487
Other operating costs.................................. 272,890 40,670 | 237,513 303,353
---------- -------- | ---------- ----------
Total operation and maintenance expenses............. 1,520,902 176,793 | 1,169,813 1,272,652
Provision for depreciation and amortization............ 244,759 35,124 | 205,918 235,001
General taxes.......................................... 56,049 8,919 | 56,582 64,398
Income taxes........................................... 171,496 18,400 | 113,478 124,019
---------- -------- | ---------- ----------
Total operating expenses and taxes................... 1,993,206 239,236 | 1,545,791 1,696,070
---------- -------- | ---------- ----------
|
OPERATING INCOME.......................................... 335,209 43,666 | 292,847 283,227
|
OTHER INCOME (EXPENSE).................................... 7,653 1,186 | (176,875) 24,146
---------- -------- | ---------- -----------
|
INCOME BEFORE NET INTEREST CHARGES........................ 342,862 44,852 | 115,972 307,373
---------- -------- | ---------- ----------
|
NET INTEREST CHARGES: |
Interest on long-term debt............................. 92,314 14,234 | 77,205 85,220
Allowance for borrowed funds used during |
construction......................................... (583) 135 | (1,665) (1,287)
Deferred interest ..................................... (8,815) (2,243) | (12,557) (7,951)
Other interest expense................................. (2,643) 1,080 | 9,427 9,879
Subsidiary's preferred stock dividend requirements..... 10,694 1,605 | 9,095 10,700
---------- -------- ---------- ----------
Net interest charges................................. 90,967 14,811 | 81,505 96,561
---------- -------- | ---------- ----------
|
NET INCOME................................................ 251,895 30,041 | 34,467 210,812
|
PREFERRED STOCK DIVIDEND REQUIREMENTS..................... 2,125 698 | 4,547 6,904
|
GAIN ON PREFERRED STOCK REACQUISITION..................... (3,589) -- | -- --
---------- --------- | ---------- ----------
|
EARNINGS ON COMMON STOCK.................................. $ 253,359 $ 29,343 | $ 29,920 $ 203,908
========== ======== | ========== ==========
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
12
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
As of December 31, 2002 2001
- ------------------------------------------------------------------------------------------------------------------
(In thousands)
ASSETS
UTILITY PLANT:
In service..................................................................... $3,478,803 $3,431,823
Less-Accumulated provision for depreciation.................................... 1,343,846 1,313,259
---------- ----------
2,134,957 2,118,564
Construction work in progress-
Electric plant............................................................... 20,687 60,482
---------- ----------
2,155,644 2,179,046
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts........................................... 106,820 114,899
Nuclear fuel disposal trust.................................................... 149,738 137,098
Long-term notes receivable from associated companies........................... 20,333 20,333
Other.......................................................................... 18,202 6,643
---------- ----------
295,093 278,973
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents...................................................... 4,823 31,424
Receivables-
Customers (less accumulated provisions of $4,509,000 and $12,923,000
respectively, for uncollectible accounts).................................. 247,624 226,392
Associated companies......................................................... 318 6,412
Other........................................................................ 20,134 20,729
Notes receivable from associated companies..................................... 77,358 --
Materials and supplies, at average cost........................................ 1,341 1,348
Prepayments and other.......................................................... 37,719 16,569
---------- ----------
389,317 302,874
---------- ----------
DEFERRED CHARGES:
Regulatory assets.............................................................. 3,199,012 3,324,804
Goodwill....................................................................... 2,000,875 1,926,526
Other.......................................................................... 12,814 27,775
---------- ----------
5,212,701 5,279,105
$8,052,755 $8,039,998
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See Consolidated Statements of Capitalization):
Common stockholder's equity.................................................... $3,274,069 $3,163,701
Preferred stock-
Not subject to mandatory redemption.......................................... 12,649 12,649
Subject to mandatory redemption.............................................. -- 44,868
Company-obligated mandatorily redeemable preferred securities.................. 125,244 125,250
Long-term debt................................................................. 1,210,446 1,224,001
---------- ----------
4,622,408 4,570,469
CURRENT LIABILITIES:
Currently payable long-term debt and preferred stock........................... 173,815 60,848
Short-term borrowings (Note 5)-
Associated companies......................................................... -- 18,149
Accounts payable-
Associated companies......................................................... 170,803 171,168
Other........................................................................ 106,504 89,739
Accrued taxes................................................................. 13,844 35,783
Accrued interest............................................................... 27,161 25,536
Other.......................................................................... 112,408 79,589
---------- ----------
604,535 480,812
---------- ----------
DEFERRED CREDITS:
Accumulated deferred income taxes.............................................. 691,721 514,216
Accumulated deferred investment tax credits.................................... 9,939 13,490
Power purchase contract loss liability ........................................ 1,710,968 1,968,823
Nuclear fuel disposal costs.................................................... 166,191 163,377
Nuclear plant decommissioning costs............................................ 135,355 137,424
Other.......................................................................... 111,638 191,387
---------- ----------
2,825,812 2,988,717
COMMITMENTS AND CONTINGENCIES
(Notes 3 and 6)................................................................. ---------- ----------
$8,052,755 $8,039,998
========== ==========
The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.
13
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31, 2002 2001
- ----------------------------------------------------------------------------------------------------------------
(Dollars in thousands, except per share amounts)
COMMON STOCKHOLDER'S EQUITY:
Common stock, par value $10 per share, authorized 16,000,000 shares
15,371,270 shares outstanding.................................................... $ 153,713 $ 153,713
Other paid-in capital.............................................................. 3,029,218 2,981,117
Accumulated other comprehensive loss (Note 4E)..................................... (865) (472)
Retained earnings (Note 4A)........................................................ 92,003 29,343
------------ ----------
Total common stockholder's equity................................................ 3,274,069 3,163,701
------------ ----------
Number of Shares Optional
Outstanding Redemption Price
---------------- --------------------
2002 2001 Per Share Aggregate
---- ---- --------- ---------
PREFERRED STOCK (Note 4B):
Cumulative, without par value-
Authorized 125,000 shares
Not Subject to Mandatory Redemption:
4% Series........................ 125,000 125,000 $106.50 $13,313 12,649 12,649
Subject to Mandatory Redemption:
8.65% Series J..................... -- 250,001 101.30 $25,325 -- 26,750
7.52% Series K..................... -- 265,000 103.76 27,496 -- 28,951
Redemption Within One Year......... -- -- -- (10,833)
------- ------- ------ ------- ------ --------
Total Subject to Mandatory
Redemption..................... -- 515,001 $52,821 -- 44,868
======= ======= ======= ------ -------
COMPANY OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF SUBSIDIARY LIMITED
PARTNERSHIP HOLDING SOLELY COMPANY
SUBORDINATED DEBENTURES (NOTE 4C):
Cumulative, $25 par value -
Authorized 5,000,000 shares
Subject to Mandatory Redemption:
8.56% due 2044.................................................................. 125,244 125,250
LONG-TERM DEBT (Note 4D):
First mortgage bonds:
9.000% due 2002................................................................... -- 50,000
6.375% due 2003................................................................... 150,000 150,000
7.125% due 2004................................................................... 160,000 160,000
6.780% due 2005................................................................... 50,000 50,000
6.850% due 2006................................................................... 40,000 40,000
8.250% due 2006................................................................... 23,053 50,000
7.900% due 2007................................................................... 18,361 40,000
7.125% due 2009................................................................... 6,300 6,300
7.100% due 2015................................................................... 12,200 12,200
9.200% due 2021................................................................... 22,963 50,000
8.320% due 2022................................................................... 40,000 40,000
8.550% due 2022................................................................... 13,623 30,000
8.820% due 2022................................................................... -- 12,000
8.850% due 2022................................................................... -- 38,000
7.980% due 2023................................................................... 40,000 40,000
7.500% due 2023................................................................... 125,000 125,000
8.450% due 2025................................................................... 50,000 50,000
6.750% due 2025................................................................... 150,000 150,000
---------- ----------
Total first mortgage bonds...................................................... 901,500 1,093,500
---------- ----------
Secured notes:
6.450% due 2006................................................................... 150,000 150,000
4.190% due 2007................................................................... 91,111 --
5.390% due 2010................................................................... 52,297 --
5.810% due 2013................................................................... 77,075 --
6.160% due 2017................................................................... 99,517 --
---------- ----------
Total secured notes............................................................. 470,000 150,000
---------- ----------
Unsecured notes:
7.69% due 2039.................................................................... 2,984 2,998
---------- -----------
Net unamortized premium on debt..................................................... 9,777 27,518
---------- ----------
Long-term debt due within one year.................................................. (173,815) (50,015)
---------- -----------
Total long-term debt............................................................ 1,210,446 1,224,001
---------- ----------
TOTAL CAPITALIZATION................................................................... $4,622,408 $4,570,469
========== ==========
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
14
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
Accumulated
Common Stock Other Other
Comprehensive Number Par Paid-In Comprehensive Retained
Income of Shares Value Capital Income (Loss) Earnings
------------- --------- ----- ------- ------------- --------
(Dollars in thousands)
Balance, January 1, 2000....................... 15,371,270 $153,713 $ 510,769 $ 7 $ 720,878
Net income.................................. $210,812 210,812
Minimum pension liability................... (15) (15)
--------
Comprehensive income........................ 210,797
--------
Cash dividends on preferred stock........... (6,904)
Cash dividends on common stock.............. (130,000)
- --------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2000..................... 15,371,270 153,713 510,769 (8) 794,786
Net income.................................. 34,467 34,467
Net unrealized gain on investments.......... 2 2
Net unrealized gain on derivative
instruments............................... 768 768
--------
Comprehensive income........................ 35,237
--------
Cash dividends on preferred stock........... (4,547)
Cash dividends on common stock ............ (175,000)
- --------------------------------------------------------------------------------------------------------------------
Balance, November 6, 2001...................... 15,371,270 153,713 510,769 762 649,706
Purchase accounting fair value adjustment... 2,470,348 (762) (649,706)
- --------------------------------------------------------------------------------------------------------------------
Balance, November 7, 2001...................... 15,371,270 153,713 2,981,117 -- --
Net income.................................. 30,041 30,041
Net unrealized gain (loss) on derivative
instruments............................... (472) (472)
--------
Comprehensive income........................ 29,569
--------
Cash dividends on preferred stock........... (698)
- ---------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001..................... 15,371,270 153,713 2,981,117 (472) 29,343
Net income.................................. 251,895 251,895
Net unrealized gain (loss) on derivative
instruments............................... (393) (393)
--------
Comprehensive income........................ $251,502
--------
Cash dividends on preferred stock........... 1,465
Cash dividends on common stock.............. (190,700)
Purchase accounting fair value adjustment . 48,101
- --------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002..................... 15,371,270 $153,713 $3,029,218 $ (865) $ 92,003
====================================================================================================================
CONSOLIDATED STATEMENTS OF PREFERRED STOCK
Not Subject to Subject to
Mandatory Redemption Mandatory Redemption
-------------------- ---------------------
Number Carrying Number Carrying
of Shares Value of Shares Value
--------- -------- --------- --------
(Dollars in thousands)
Balance, January 1, 2000............ 125,000 $12,649 5,840,000 $209,000
Redemptions-
7.52% Series.................... (50,000) (5,000)
8.65% Series.................... ( 166,666) (16,667)
-----------------------------------------------------------------------------------------
Balance, December 31, 2000.......... 125,000 12,649 5,623,334 187,333
Redemptions-
7.52% Series.................... (25,000) (2,500)
8.65% Series.................... (83,333) (8,333)
Purchase accounting fair
value adjustment............. 4,451
-----------------------------------------------------------------------------------------
Balance, December 31, 2001.......... 125,000 12,649 5,515,001 180,951
Redemptions-
7.52% Series.................... (265,000) (28,951)
8.65% Series.................... (250,001) (26,750)
Purchase accounting fair
value adjustment............. (6)
-----------------------------------------------------------------------------------------
Balance, December 31, 2002.......... 125,000 $12,649 5,000,000 $125,244
=========================================================================================
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
15
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Nov. 7 - Jan. 1 -
2002 Dec. 31, 2001 Nov. 6, 2001 2000
- -----------------------------------------------------------------------------------------------------------------------
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income........................................................ $ 251,895 $ 30,041 | $ 34,467 $ 210,812
Adjustments to reconcile net income to net |
cash from operating activities: |
Provision for depreciation and amortization.................. 244,759 35,124 | 205,918 235,001
Nuclear fuel and lease amortization.......................... -- -- | -- 11,472
Other amortization........................................... 849 1,360 | 23,025 34,563
Deferred costs recoverable as regulatory assets.............. (285,065) (25,471) | (29,312) (229,321)
Deferred income taxes, net................................... 115,866 5,609 | (58,132) 270,479
Investment tax credits, net.................................. (3,551) (540) | (3,057) (15,027)
Receivables.................................................. (14,542) 7,050 | 27,177 11,766
Materials and supplies....................................... 7 2 | (842) (268)
Accounts payable............................................. 16,399 (5,060) | (44,498) 51,633
Other (Note 7)............................................... (17,642) 20,563 | 66,328 (230,100)
--------- -------- | --------- ---------
Net cash provided from operating activities................ 308,975 68,678 | 221,074 351,010
--------- -------- | --------- ---------
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
New Financing- |
Long-term debt............................................... 318,106 -- | 148,796 --
Short-term borrowings, net................................... -- -- | -- 29,200
Redemptions and Repayments- |
Preferred stock.............................................. (51,500) -- | (10,833) (21,667)
Long-term debt............................................... (196,033) (40,000) | -- (40,000)
Short-term borrowings, net................................... (18,149) (1,851) | (9,200) --
Capital lease payments....................................... -- -- | -- (48,516)
Dividend Payments- |
Common stock................................................. (190,700) -- | (175,000) (130,000)
Preferred stock.............................................. (2,125) (698) | (4,547) (7,065)
--------- -------- | --------- ----------
Net cash used for financing activities..................... (140,401) (42,549) | (50,784) (218,048)
--------- -------- | ---------- ----------
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
Property additions............................................. (97,346) (21,487) | (141,030) (144,389)
Contributions to decommissioning trusts........................ -- (202) | (1,004) (130,444)
Sale of investments............................................ -- -- | -- 74,797
Loans to associated companies.................................. (77,358) -- | -- --
Other.......................................................... (20,471) (1,078) | (2,215) (624)
--------- -------- | ----------- ---------
Net cash used for investing activities..................... (195,175) (22,767) | (144,249) (200,660)
--------- -------- | --------- ----------
|
|
Net increase (decrease) in cash and cash equivalents.............. (26,601) 3,362 | 26,041 (67,698
Cash and cash equivalents at beginning of period.................. 31,424 28,062 | 2,021 69,719
--------- -------- | --------- ---------
Cash and cash equivalents at end of period........................ $ 4,823 $ 31,424 | $ 28,062 $ 2,021
========= ======== | ========= =========
|
SUPPLEMENTAL CASH FLOWS INFORMATION: |
Cash Paid During the Year- |
Interest (net of amounts capitalized)........................ $ 92,152 $ 4,787 | $ 95,509 $ 99,961
========= ======== | ========= =========
Income taxes (refund)........................................ $ 83,776 $ 20,586 | $ 19,365 $ (50,105)
========= ======== | ========= =========
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
16
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF TAXES
Nov. 7 - Jan. 1 -
2002 Dec. 31, 2001 Nov. 6, 2001 2000
- ---------------------------------------------------------------------------------------------------------------------
(In thousands)
GENERAL TAXES:
Real and personal property....................................... $ 4,362 $ 283 | $ 3,589 $ 4,093
State gross receipts............................................. -- 1,269 | -- --
Social security and unemployment................................. -- (1) | 7 --
New Jersey Transitional Energy Facilities Assessment*............ 39,387 6,765 | 42,418 47,521
Other............................................................ 12,300 603 | 10,568 12,784
-------- --------- | --------- ---------
Total general taxes....................................... $ 56,049 $ 8,919 | $ 56,582 $ 64,398
======== ========= | ========= =========
|
PROVISION FOR INCOME TAXES: |
Currently payable- |
Federal....................................................... $ 55,731 $ 11,827 | $ 41,826 $(109,572)
State......................................................... 13,809 3,205 | 19,415 (26,005)
-------- --------- | --------- ---------
`69,540 15,032 | 61,241 (135,577)
-------- --------- | --------- ---------
Deferred, net- |
Federal....................................................... 88,758 4,268 | (36,210) 209,127
State......................................................... 27,108 1,341 | (21,922) 61,352
-------- --------- | --------- ----------
115,866 5,609 | (58,132) 270,479
-------- --------- | --------- ---------
Investment tax credit amortization............................... (3,551) (540) | (3,057) (15,027)
-------- --------- | --------- ---------
Total provision for income taxes.......................... $181,855 $ 20,101$ | $ 52 $ 119,875
======== ========== | ========= =========
|
INCOME STATEMENT CLASSIFICATION |
OF PROVISION FOR INCOME TAXES: |
Operating income................................................. $171,496 $ 18,400 | $ 113,478 $ 124,019
Other income..................................................... 10,359 1,701 | (113,426) (4,144)
-------- --------- | --------- ---------
Total provision for income taxes.......................... $181,855 $ 20,101 | 52 $ 119,875
======== ========= | ========= =========
|
RECONCILIATION OF FEDERAL INCOME TAX |
EXPENSE AT STATUTORY RATE TO TOTAL |
PROVISION FOR INCOME TAXES: |
Book income before provision for income taxes.................... $433,749 $ 50,142 | $ 34,519 $ 330,688
======== ========= | ========= =========
Federal income tax expense at statutory rate..................... $151,812 $ 17,550 | $ 12,082 $ 115,741
Increases (reductions) in taxes resulting from- |
Amortization of investment tax credits........................ (3,550) (540) | (3,057) (15,027)
Depreciation.................................................. 7,154 226 | 3,563 3,230
State income tax, net of federal benefit...................... 27,111 3,077 | 4,355 21,987
Allocated share of consolidated tax savings................... -- -- | (8,509) --
Sale of generation assets..................................... -- -- | -- (6,239)
Other, net.................................................... (672) (212) | (8,382) 183
-------- --------- | ---------- ---------
Total provision for income taxes.......................... $181,855 $ 20,101 | $ 52 $ 119,875
======== ========= | ========== =========
|
ACCUMULATED DEFERRED INCOME TAXES AT |
DECEMBER 31: |
Property basis differences....................................... $297,983 $ 288,255 | $ 302,476
Nuclear decommissioning.......................................... 44,775 59,716 | 97,817
Deferred sale and leaseback costs................................ (16,451) (16,240) | (15,605)
Purchase accounting basis difference............................. (1,253) (71,900) | --
Sale of generation assets........................................ (17,861) 184,625 | 235,923
Regulatory transition charge..................................... 224,117 123,042 | 99,930
Provision for rate refund........................................ (29,370) (46,942) | (46,942)
Customer receivables for future income taxes..................... (5,336) 16,749 | 33,234
Oyster Creek securitization...................................... 202,448 -- | --
Other............................................................ (7,331) (23,089) | (40,786)
-------- --------- | ---------
Net deferred income tax liability......................... $691,721 $ 514,216 | $ 666,047
======== ========= | =========
* Collected from customers through regulated rates and included in revenue on the Consolidated Statements of Income.
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
17
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
The consolidated financial statements include Jersey Central Power &
Light Company (Company) and its wholly owned subsidiaries. All significant
intercompany transactions have been eliminated. The Company is a wholly owned
subsidiary of FirstEnergy Corp. FirstEnergy also holds directly all of the
issued and outstanding common shares of Ohio Edison Company (OE), The Cleveland
Electric Illuminating Company (CEI), The Toledo Edison Company (TE), American
Transmission Systems, Inc. (ATSI), Metropolitan Edison Company (Met-Ed) and
Pennsylvania Electric Company (Penelec). The Company, Met-Ed and Penelec were
formerly wholly owned subsidiaries of GPU, Inc., which merged with FirstEnergy
on November 7, 2001. Pre-merger and post-merger period financial results are
separated by a heavy black line.
The Company follows the accounting policies and practices prescribed by
the Securities and Exchange Commission (SEC), the New Jersey Board of Public
Utilities (NJBPU) and the Federal Energy Regulatory Commission (FERC). The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States (GAAP) requires management to make
periodic estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses and the disclosure of contingent assets and
liabilities. Actual results could differ from these estimates. Certain prior
year amounts have been reclassified to conform with the current year
presentation.
(A) CONSOLIDATION-
The Company consolidates all majority-owned subsidiaries, after
eliminating the effects of intercompany transactions. Non-majority owned
investments, including investments in limited liability companies, partnerships
and joint ventures, are accounted for under the equity method when the Company
is able to influence their financial or operating policies. Investments in
corporations resulting in voting control of 20% or more are presumed to be
equity method investments. Limited partnerships are evaluated in accordance with
SEC Staff D-46, "Accounting for Limited Partnership Investments" and American
Institute of Certified Public Accountants (AICPA) Statement of Position (SOP)
78-9, "Accounting for Investments in Real Estate Ventures," which specify a 3 to
5 percent threshold for the presumption of influence. For all remaining
investments (excluding those within the scope of Statement of Financial
Accounting Standards (SFAS) 115, the Company applies the cost method.
(B) REVENUES-
The Company's principal business is providing electric service to
customers in New Jersey. The Company's retail customers are metered on a cycle
basis. Revenue is recognized for unbilled electric service provided through the
end of the year. See Note 7 - Other Information for discussion of reporting of
independent system operator transactions.
Receivables from customers include sales to residential, commercial and
industrial customers and sales to wholesale customers. There was no material
concentration of receivables as of December 31, 2002 or 2001, with respect to
any particular segment of the Company's customers.
(C) REGULATORY PLAN-
New Jersey continues to evolve to a competitive electric utility
marketplace. In 2001, the NJBPU issued a Final Decision and Order (Final Order)
with respect to the Company's rate unbundling, stranded cost and restructuring
filings, which superseded its 1999 Summary Order. The Final Order confirmed rate
reductions set forth in the 1999 Summary Order, which remain in effect at
increasing levels through July 2003, confirmed the right of customers to select
their generation supplier and deregulated electric generation service costs. The
Final Order also confirmed the establishment of a non-bypassable societal
benefits charge to recover costs including nuclear plant decommissioning and
manufactured gas plant remediation, as well as a non-bypassable market
transition charge primarily to recover stranded costs. The NJBPU has deferred
making a final determination of the net proceeds and stranded costs related to
prior generating asset divestitures until the Company's request for an Internal
Revenue Service (IRS) ruling regarding the treatment of associated federal
income tax benefits is acted upon. Should the IRS ruling support the return of
the tax benefits to customers, there would be no effect to the Company's net
income since the contingency existed prior to the Company being acquired by
FirstEnergy.
In addition, the Final Order provided for the ability to securitize
stranded costs associated with the divested Oyster Creek Nuclear Generating
Station. In February 2002, the Company received NJBPU authorization to issue
$320 million of transition bonds to securitize the recovery of these costs. The
NJBPU order also provided for a usage-based non-bypassable transition bond
charge and for the transfer of the bondable transition property to another
entity. JCP&L sold $320 million of transition bonds through its wholly owned
subsidiary, JCP&L Transition Funding LLC, in June 2002 - those bonds are
recognized on the Consolidated Balance Sheet (see Note 4F).
18
The Company obtains its supply of electricity almost entirely from
contracted and open market purchases. The Company is permitted to defer for
future collection from customers the amounts by which its costs for supplying
non-shopping customers and costs incurred under non-utility generation
agreements exceed amounts collected through its Basic Generation Service (BGS)
and market transition charge rates. As of December 31, 2002, the accumulated
deferred cost balance totaled approximately $549 million. The NJBPU also allowed
securitization of the Company's deferred balance to the extent permitted by law
upon application by the Company and a determination by the NJBPU that the
conditions of the New Jersey restructuring legislation are met. There can be no
assurance as to the extent, if any, that the NJBPU will permit such
securitization.
Under New Jersey transition legislation, all electric distribution
companies, including the Company, were required to file rate cases to determine
the level of unbundled rate components to become effective August 1, 2003. On
August 1, 2002, the Company submitted two rate filings with the NJBPU. The first
filing requested increases in base electric rates of approximately $98 million
annually. The second filing was a request to recover deferred costs that
exceeded amounts being recovered under the current market transition charge and
societal benefits charge rates; one proposed method of recovery of these costs
is the securitization of the deferred balance. This securitization methodology
is similar to the Oyster Creek securitization discussed above. Hearings began in
February 2003. The Administrative Law Judge's recommended decision is due in
June 2003 and the NJBPU's subsequent decision is due in July 2003.
In December 2001, the NJBPU authorized the auctioning of BGS for the
period from August 1, 2002 through July 31, 2003 to meet the electricity demands
of all customers who have not selected an alternative supplier. The auction
results were approved by the NJBPU in February 2002, removing the Company's BGS
obligation of 5,100 MW for the period August 1, 2002 through July 31, 2003. In
February 2003, the NJBPU approved the BGS auction results for the period
beginning August 1, 2003. The auction covered a fixed price bid (applicable to
all residential and smaller commercial and industrial customers) and a hourly
price bid (applicable to all large industrial customers) process. The Company
will sell all self-supplied energy (non-utility generation and owned generation)
to the wholesale market with offsets to its deferred energy cost balances.
The application of SFAS 71, "Accounting for the Effects of Certain Types
of Regulation," was discontinued in 1999 with respect to the Company's
generation operations. The Company subsequently divested substantially all of
its generating assets. The SEC issued interpretive guidance regarding asset
impairment measurement, concluding that any supplemental regulated cash flows
such as a Competitive Transition Charge should be excluded from the cash flows
of assets in a portion of the business not subject to regulatory accounting
practices. If those assets are impaired, a regulatory asset should be
established if the costs are recoverable through regulatory cash flows. Net
assets included in utility plant relating to operations for which the
application of SFAS 71 was discontinued were $44 million as of December 31,
2002.
(D) PROPERTY, PLANT AND EQUIPMENT-
As a result of the merger, a portion of the Company's property, plant
and equipment was adjusted to reflect fair value. The majority of the Company's
property, plant and equipment is reflected at original cost since such assets
remain subject to rate regulation on a historical cost basis. In addition to its
wholly owned facilities, the Company holds a 50% ownership interest in Yards
Creek Pumped Storage Facility, and its net book value was approximately $21.3
million as of December 31, 2002. The Company's accounting policy for planned
major maintenance projects is to recognize liabilities as they are incurred.
The Company provides for depreciation on a straight-line basis at
various rates over the estimated lives of property included in plant in service.
The annualized composite rate was approximately 3.5% in 2002, 3.4% in 2001 and
3.3% in 2000.
Annual depreciation expense in 2002 included approximately $26.2 million
for future decommissioning costs applicable to the Company's ownership in Unit 2
of the Three Mile Island Nuclear Plant (TMI-2), a demonstration nuclear reactor
(Saxton Nuclear Experimental Facility) owned by a wholly owned subsidiary of the
Company (in conjunction with Met-Ed and Penelec) and decommissioning liabilities
for its previously divested nuclear generating units. The Company's share of the
future obligation to decommission these units is approximately $132.0 million in
current dollars and (using a 4.0% escalation rate) approximately $210.1 million
in future dollars. The estimated obligation and the escalation rate were
developed based on site specific studies. Decommissioning of the demonstration
nuclear reactor is expected to be completed in 2003; payments for
decommissioning of the nuclear generating units are expected to begin in 2014,
when actual decommissioning work is expected to begin. The Company has recovered
approximately $34.0 million for future decommissioning through its electric
rates from customers through December 31, 2002. The Company has also recognized
an estimated liability of approximately $9.9 million related to decontamination
and decommissioning of nuclear enrichment facilities operated by the United
States Department of Energy (DOE), as required by the Energy Policy Act of 1992.
19
In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement
Obligations". The new statement provides accounting standards for retirement
obligations associated with tangible long-lived assets, with adoption required
by January 1, 2003. SFAS 143 requires that the fair value of a liability for an
asset retirement obligation be recorded in the period in which it is incurred.
The associated asset retirement costs are capitalized as part of the carrying
amount of the long-lived asset. Over time the capitalized costs are depreciated
and the present value of the asset retirement liability increases, resulting in
a period expense. However, rate-regulated entities may recognize a regulatory
asset or liability instead, if the criteria for such treatment are met. Upon
retirement, a gain or loss would be recorded if the cost to settle the
retirement obligation differs from the carrying amount.
The Company has identified applicable legal obligations as defined
under the new standard, principally for nuclear power plant decommissioning.
Upon adoption of SFAS 143 in January 2003, asset retirement costs of $98 million
were recorded as part of the carrying amount of the related long-lived asset,
offset by accumulated depreciation of $98 million. The asset retirement
liability at the date of adoption was $104 million. As of December 31, 2002, the
Company had recorded decommissioning liabilities of $130 million. The change in
the estimated liabilities resulted from changes in methodology and various
assumptions, including changes in the projected dates for decommissioning.
Management expects that substantially all of the nuclear decommissioning
costs will be recoverable through regulated rates. Therefore, the Company
recognized a regulatory liability of $26 million upon adoption of SFAS 143 for
the transition amounts related to establishing the asset retirement obligations
for nuclear decommissioning.
The FASB approved SFAS 141, "Business Combinations" and SFAS 142,
"Goodwill and Other Intangible Assets," on June 29, 2001. SFAS 141 requires all
business combinations initiated after June 30, 2001, to be accounted for using
purchase accounting. The provisions of the new standard relating to the
determination of goodwill and other intangible assets have been applied to the
FirstEnergy/GPU merger, which was accounted for as a purchase transaction, and
have not materially affected the accounting for this transaction. Under SFAS
142, amortization of existing goodwill ceased January 1, 2002. Instead, goodwill
is tested for impairment at least on an annual basis - based on the results of
the transition analysis and the 2002 annual analysis, no impairment of the
Company's goodwill is required.
(E) STOCK-BASED COMPENSATION-
FirstEnergy applies the recognition and measurement principles of
Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock
Issued to Employees" and related Interpretations in accounting for its
stock-based compensation plans (see Note 4B). No material stock-based employee
compensation expense is reflected in net income as all options granted under
those plans had an exercise price equal to the market value of the underlying
common stock on the grant date, resulting in substantially no intrinsic value.
If FirstEnergy had accounted for employee stock options under the fair
value method, a higher value would have been assigned to the options granted.
The weighted average assumptions used in valuing the options and their resulting
estimated fair values would be as follows:
2002 2001 2000
----------------------------------------------------------------------------
Valuation assumptions:
Expected option term (years). 8.1 8.3 7.6
Expected volatility.......... 23.31% 23.45% 21.77%
Expected dividend yield...... 4.36% 5.00% 6.68%
Risk-free interest rate...... 4.60% 4.67% 5.28%
Fair value per option.......... $6.45 $4.97 $2.86
----------------------------------------------------------------------------
The effects of applying fair value accounting to the FirstEnergy's stock
options would not materially affect the Company's net income.
20
(F) INCOME TAXES-
Details of the total provision for income taxes are shown on the
Consolidated Statements of Taxes. Deferred income taxes result from timing
differences in the recognition of revenues and expenses for tax and accounting
purposes. Investment tax credits, which were deferred when utilized, are being
amortized over the recovery period of the related property. The liability method
is used to account for deferred income taxes. Deferred income tax liabilities
related to tax and accounting basis differences are recognized at the statutory
income tax rates in effect when the liabilities are expected to be paid. Results
for the period January 1, 2001 through November 6, 2001 were included in the
final consolidated federal income tax return of GPU, and results for the period
November 7, 2001 through December 31, 2001 were included in FirstEnergy's 2001
consolidated federal income tax return. The consolidated tax liability is
allocated on a "stand-alone" company basis, with the Company recognizing the tax
benefit for any tax losses or credits it contributed to the consolidated return.
(G) RETIREMENT BENEFITS-
Effective December 31, 2001, the Company's defined benefit pension plan
was merged into FirstEnergy's defined benefit pension plan. FirstEnergy's
trusteed, noncontributory defined benefit pension plan covers almost all of the
Company's full-time employees. Upon retirement, employees receive a monthly
pension based on length of service and compensation. FirstEnergy uses the
projected unit credit method for funding purposes. The assets of the pension
plan consist primarily of common stocks, United States government bonds and
corporate bonds. Costs for the year 2001 include the former GPU companies'
pension and other postretirement benefit costs for the period November 7, 2001
through December 31, 2001.
The Company provides a minimum amount of noncontributory life insurance
to retired employees in addition to optional contributory insurance. Health care
benefits, which include certain employee contributions, deductibles and
copayments, are also available to retired employees, their dependents and, under
certain circumstances, their survivors. The Company pays insurance premiums to
cover a portion of these benefits in excess of set limits; all amounts up to the
limits are paid by the Company. The Company recognizes the expected cost of
providing other postretirement benefits to employees and their beneficiaries and
covered dependents from the time employees are hired until they become eligible
to receive those benefits.
The following sets forth the funded status of the plans and amounts
recognized on FirstEnergy's Consolidated Balance Sheet as of December 31:
21
Other
Pension Benefits Postretirement Benefits
---------------- -----------------------
2002 2001 2002 2001
- ------------------------------------------------------------------------------------------------
(In millions)
Change in benefit obligation:
Benefit obligation as of January 1........ $3,547.9 $1,506.1 $ 1,581.6 $ 752.0
Service cost.............................. 58.8 34.9 28.5 18.3
Interest cost............................. 249.3 133.3 113.6 64.4
Plan amendments........................... -- 3.6 (121.1) --
Actuarial loss............................ 268.0 123.1 440.4 73.3
Voluntary early retirement program........ -- -- -- 2.3
GPU acquisition........................... (11.8) 1,878.3 110.0 716.9
Benefits paid............................. (245.8) (131.4) (83.0) (45.6)
-------------------------------------------------------------------------------------------
Benefit obligation as of December 31...... 3,866.4 3,547.9 2,070.0 1,581.6
-------------------------------------------------------------------------------------------
Change in fair value of plan assets:
Fair value of plan assets as of January 1. 3,483.7 1,706.0 535.0 23.0
Actual return on plan assets.............. (348.9) 8.1 (57.1) 12.7
Company contribution...................... -- -- 37.9 43.3
GPU acquisition........................... -- 1,901.0 -- 462.0
Benefits paid............................. (245.8) (131.4) (42.5) (6.0)
-------------------------------------------------------------------------------------------
Fair value of plan assets as of December 31 2,889.0 3,483.7 473.3 535.0
--------------------------------------------------------------------------------------------
Funded status of plan..................... (977.4) (64.2) (1,596.7) (1,046.6)
Unrecognized actuarial loss............... 1,185.8 222.8 751.6 212.8
Unrecognized prior service cost........... 78.5 87.9 (106.8) 17.7
Unrecognized net transition obligation.... -- -- 92.4 101.6
-------------------------------------------------------------------------------------------
Net amount recognized..................... $ 286.9 $ 246.5 $ (859.5) $ (714.5)
===========================================================================================
Consolidated Balance Sheets classifications:
Prepaid (accrued) benefit cost............ $(548.6) $ 246.5 $ (859.5) $ (714.5)
Intangible asset.......................... 78.5 -- -- --
Accumulated other comprehensive loss...... 757.0 -- -- --
-------------------------------------------------------------------------------------------
Net amount recognized..................... $ 286.9 $ 246.5 $ (859.5) $ (714.5)
============================================================================================
Assumptions used as of December 31:
Discount rate............................. 6.75% 7.25% 6.75% 7.25%
Expected long-term return on plan assets.. 9.00% 10.25% 9.00% 10.25%
Rate of compensation increase............. 3.50% 4.00% 3.50% 4.00%
Net pension and other postretirement benefit costs for the two years
ended December 31, 2002 were computed as follows:
Other
Pension Benefits Postretirement Benefits
-------------------- -----------------------
2002 2001 2002 2001
--------------------------------------------------------------------------------------------------
(In millions)
Service cost........................... $ 58.8 $ 34.9 $ 28.5 $18.3
Interest cost.......................... 249.3 133.3 113.6 64.4
Expected return on plan assets......... (346.1) (204.8) (51.7) (9.9)
Amortization of transition obligation
(asset).............................. -- (2.1) 9.2 9.2
Amortization of prior service cost..... 9.3 8.8 3.2 3.2
Recognized net actuarial loss (gain)... -- -- 11.2 4.9
Voluntary early retirement program..... -- 6.1 -- 2.3
--------------------------------------------------------------------------------------------------
Net periodic benefit cost (income)..... $ (28.7) $ (23.8) $114.0 $92.4
==================================================================================================
The composite health care cost trend rate assumption is approximately
10%-12% in 2003, 9% in 2004 and 8% in 2005, decreasing to 5% in later years.
Assumed health care cost trend rates have a significant effect on the amounts
reported for the health care plan. An increase in the health care cost trend
rate assumption by one percentage point would increase the total service and
interest cost components by $20.7 million and the postretirement benefit
obligation by $232.2 million. A decrease in the same assumption by one
percentage point would decrease the total service and interest cost components
by $16.7 million and the postretirement benefit obligation by $204.3 million.
A significant portion of the services provided to the Company are from
affiliates, GPU Service, Inc. (GPUS) and FirstEnergy Service Company (FECO) (see
Note 1H). Therefore, substantially all of the employees are with GPUS which
bills the Company for services rendered. See Note 7D for the Company's amount of
net pension and other postretirement benefit costs reflected in its Consolidated
Statements of Income.
22
(H) TRANSACTIONS WITH AFFILIATED COMPANIES-
Operating revenues, operating expenses and other income include
transactions with affiliated companies, primarily GPUS and FirstEnergy Solutions
(FES). During the three years ended December 31, 2002, GPUS provided legal,
accounting, financial and other services to the Company. The Company also
entered into sale and purchase transactions with affiliates (Met-Ed and Penelec)
during the period. Through the BGS auction process, FES is an alternate supplier
of power to the Company.
FirstEnergy does not bill directly or allocate any of its costs to any
subsidiary company. Costs are allocated to the Company from its affiliates, GPUS
and FECO, both subsidiaries of FirstEnergy Corp. and both "mutual service
companies" as defined in Rule 93 of the 1935 Public Utility Holding Company Act
(PUHCA). The majority of costs are directly billed or assigned at no more than
cost as determined by PUHCA Rule 91. The remaining costs are for services that
are provided on behalf of more than one company, or costs that cannot be
precisely identified and are allocated using formulas that are filed annually
with the SEC on Form U-13-60. The current allocation or assignment formulas used
and their bases include multiple factor formulas: the ratio of each company's
amount of FirstEnergy's aggregate direct payroll, number of employees, asset
balances, revenues, number of customers and other factors; and specific
departmental charge ratios. Management believes that these allocation methods
are reasonable.
(I) SUPPLEMENTAL CASH FLOWS INFORMATION-
All temporary cash investments purchased with an initial maturity of
three months or less are reported as cash equivalents on the Consolidated
Balance Sheets at cost, which approximates their fair market value.
All borrowings with initial maturities of less than one year are defined
as financial instruments under GAAP and are reported on the Consolidated Balance
Sheets at cost, which approximates their fair market value. The following sets
forth the approximate fair value and related carrying amounts of all other
long-term debt, preferred stock subject to mandatory redemption and investments
other than cash and cash equivalents as of December 31:
2002 2001
- -------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Value Value Value Value
- -------------------------------------------------------------------------------
(In millions)
Long-term debt..................... $1,374 $ 1,415 $1,246 $1,250
Preferred stock.................... $ 125 $ 127 $ 176 $ 180
Investments other than cash
and cash equivalents............. $ 258 $ 258 $ 253 $ 252
The fair values of long-term debt and preferred stock reflect the
present value of the cash outflows relating to those securities based on the
current call price, the yield to maturity or the yield to call, as deemed
appropriate at the end of each respective year. The yields assumed were based on
securities with similar characteristics offered by corporations with credit
ratings similar to the Company's ratings. In 2001, long-term debt and preferred
stock subject to mandatory redemption were recognized at fair value in
connection with the merger.
The fair value of investments other than cash and cash equivalents
represents cost (which approximates fair value) or the present value of the cash
inflows based on the yield to maturity. The yields assumed were based on
financial instruments with similar characteristics and terms. Investments other
than cash and cash equivalents include decommissioning trust investments. The
Company has no securities held for trading purposes.
The investment policy for the nuclear decommissioning trust funds
restricts or limits the ability to hold certain types of assets including
private or direct placements, warrants, securities of FirstEnergy, investments
in companies owning nuclear power plants, financial derivatives, preferred
stocks, securities convertible into common stock and securities of the trust
fund's custodian or managers and their parents or subsidiaries. The investments
that are held in the decommissioning trusts (included as "Investments other than
cash and cash equivalents" in the table above) consist of equity securities,
government bonds and corporate bonds. Unrealized gains and losses applicable to
the decommissioning trusts have been recognized in the trust investment with a
corresponding change to the decommissioning liability. Realized gains (losses)
are recognized as additions (reductions) to trust asset balances. For the year
2002, net realized losses were approximately $0.06 million and interest and
dividend income totaled approximately $3.6 million.
On January 1, 2001, the Company adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended by SFAS 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities --
an amendment of FASB Statement No. 133." The adoption resulted in the
recognition of derivative assets on the Consolidated Balance Sheet as of January
1, 2001 in the amount of $21.8 million with offsetting amounts, net of tax,
recorded in Accumulated Other Comprehensive Income, of $5.1 million, and in
Regulatory Assets, of $13 million.
The Company is exposed to financial risks resulting from the fluctuation
of commodity prices, including electricity and natural gas. To manage the
volatility relating to these exposures, the Company uses a variety of
non-derivative and derivative instruments, including forward contracts, options
and futures contracts. These derivatives are used principally for hedging
purposes. The Company has a Risk Policy Committee, comprised of FirstEnergy
executive officers, which exercises an independent risk oversight function to
ensure compliance with corporate risk management policies and prudent risk
management practices.
The Company uses derivatives to hedge the risk of price fluctuations.
The Company's primary ongoing hedging activity involves cash flow hedges of
electricity and natural gas purchases. The majority of the Company's forward
commodity contracts are considered "normal purchases and sales," as defined by
SFAS 133, and are therefore excluded from the scope of SFAS 138. The forward
contracts, options and futures contracts determined to be within the scope of
SFAS 133 are accounted for as cash flow hedges and expire on various dates
through 2003. Gains and losses from hedges of commodity price risks are included
in net income when the underlying hedged commodities are delivered. There is
currently a net deferred loss of $0.4 million included in Accumulated Other
Comprehensive Loss as of December 31, 2002 related to derivative hedging
activity, which will be reclassified to earnings during the next twelve months
as hedged transactions occur.
(J) REGULATORY ASSETS-
The Company recognizes, as regulatory assets, costs which the FERC and
NJBPU have authorized for recovery from customers in future periods. Without
such authorization, the costs would have been charged to income as incurred. All
regulatory assets are expected to continue to be recovered from customers under
the Company's regulatory plan. The Company continues to bill and collect
cost-based rates for its transmission and distribution services, which remain
regulated; accordingly, it is appropriate that the Company continues the
application of SFAS 71 to those operations.
Net regulatory assets on the Consolidated Balance Sheets are comprised
of the following:
2002 2001
-----------------------------------------------------------------------------
(In millions)
Regulatory transition charge................... $2,801.7 $2,844.7
Societal benefits charge....................... 143.8 166.6
Property losses and unrecovered plant costs.... 87.8 104.1
Customer receivables for future income taxes... 34.5 52.4
Employee postretirement benefit costs.......... 33.2 36.5
Loss on reacquired debt........................ 17.4 19.3
Spent fuel disposal costs...................... 8.8 20.2
Other.......................................... 71.8 81.0
-----------------------------------------------------------------------------
Total....................................... $3,199.0 $3,324.8
=============================================================================
2. MERGER:
On November 7, 2001, the merger of FirstEnergy and GPU became effective
pursuant to the Agreement and Plan of Merger, dated August 8, 2000. As a result
of the merger, GPU's former wholly owned subsidiaries, including the Company,
became wholly owned subsidiaries of FirstEnergy.
The merger was accounted for by the purchase method of accounting. The
assets acquired and liabilities assumed were recorded at estimated fair values
as determined by FirstEnergy's management based on information currently
available and on current assumptions as to future operations. Merger purchase
accounting adjustments recorded in the records of the Company primarily consist
of: (1) revaluation of certain property, plant and equipment; (2) adjusting
preferred stock subject to mandatory redemption and long-term debt to estimated
fair value; (3) recognizing additional obligations related to retirement
benefits; and (4) recognizing estimated severance and other compensation
liabilities. Other assets and liabilities were not adjusted since they remain
subject to rate regulation on a historical cost basis. The excess of the
purchase price over the estimated fair values of the assets acquired and
liabilities assumed was recognized as goodwill.
During 2002, certain pre-acquisition contingencies and other final
adjustments to the fair values of the assets acquired and liabilities assumed
were reflected in the final allocation of the purchase price. These adjustments
primarily related to: (1) final actuarial calculations related to pension and
postretirement benefit obligations and (2) return to accrual adjustments for
income taxes. As a result of these adjustments, goodwill increased by
approximately $74.3 million. As of December 31, 2002, the Company had recorded
goodwill of approximately $2.0 billion related to the merger.
24
3. LEASES:
Consistent with regulatory treatment, the rentals for capital and
operating leases are charged to operating expenses on the Consolidated
Statements of Income. Prior to the sale of its nuclear generating facilities
(completed in 2000), the Company's capital lease obligations related primarily
to nuclear fuel lease agreements with nonaffiliated fuel trusts for the plants.
In 2000, total rentals related to these capital leases were $13.0 million,
comprised of an interest element of $1.5 million and other costs of $11.5
million. The Company's most significant operating lease relates to the sale and
leaseback of a portion of its ownership interest in the Merrill Creek Reservoir
project. The interest element related to this lease was $1.2 million, $1.2
million and $0.4 million for the years 2002, 2001 and 2000, respectively.
As of December 31, 2002, the future minimum lease payments on the
Company's Merrill Creek operating lease, net of reimbursements from sublessees,
are: $3.2 million, $1.2 million, $1.7 million, $1.6 million and $1.6 million for
the years 2003 through 2007, respectively, and $56.7 million for the years
thereafter. The Company is recovering its Merrill Creek lease payments, net of
reimbursements, through its distribution rates.
4. CAPITALIZATION:
(A) RETAINED EARNINGS-
The merger purchase accounting adjustments included resetting the
retained earnings balance to zero as of the November 7, 2001 merger date.
In general, the Company's first mortgage bond (FMB) indentures restrict
the payment of dividends or distributions on or with respect to the Company's
common stock to amounts credited to earned surplus since approximately the date
of its indenture. At such date, the Company had a balance of $1.7 million in its
earned surplus account, which would not be available for dividends or other
distributions. As of December 31, 2002, the Company had retained earnings
available to pay common stock dividends of $90.3 million, net of amounts
restricted under the Company's FMB indentures.
(B) STOCK COMPENSATION PLANS-
In 2001, FirstEnergy assumed responsibility for two new stock-based
plans as a result of its acquisition of GPU. No further stock-based compensation
can be awarded under the GPU, Inc. Stock Option and Restricted Stock Plan for
MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU,
Inc. and Subsidiaries (GPU Plan). All options and restricted stock under both
Plans have been converted into FirstEnergy options and restricted stock. Options
under the GPU Plan became fully vested on November 7, 2001, and will expire on
or before June 1, 2010. Under the MYR Plan, all options and restricted stock
maintained their original vesting periods, which range from one to four years,
and will expire on or before December 17, 2006.
Additional stock based plans administered by FirstEnergy include the
Centerior Equity Plan (CE Plan) and the FirstEnergy Executive and Director
Incentive Compensation Plan (FE Plan). All options are fully vested under the CE
Plan, and no further awards are permitted. Outstanding options will expire on or
before February 25, 2007. Under the FE Plan, total awards cannot exceed 22.5
million shares of common stock or their equivalent. Only stock options and
restricted stock have been granted, with vesting periods ranging from six months
to seven years.
Collectively, the above plans are referred to as the FE Programs.
Restricted common stock grants under the FE Programs were as follows:
2002 2001 2000
- ------------------------------------------------------------------------------
Restricted common shares granted......... 36,922 133,162 208,400
Weighted average market price ........... $36.04 $35.68 $26.63
Weighted average vesting period (years).. 3.2 3.7 3.8
Dividends restricted..................... Yes * Yes
----------------------------------------------------------------------------
* FE Plan dividends are paid as restricted stock on 4,500 shares; MYR Plan
dividends are paid as unrestricted cash on 128,662 shares
Under the Executive Deferred Compensation Plan (EDCP), covered employees
can direct a portion of their Annual Incentive Award and/or Long-Term Incentive
Award into an unfunded FirstEnergy Stock Account to receive vested stock units.
An additional 20% premium is received in the form of stock units based on the
amount allocated to the FirstEnergy Stock Account. Dividends are calculated
quarterly on stock units outstanding and are paid in the form of additional
stock units. Upon withdrawal, stock units are converted to FirstEnergy shares.
Payout typically occurs three years from the date of deferral; however, an
election can be made in the year prior to payout to further defer shares into a
retirement stock account that will pay out in cash upon retirement. As of
December 31, 2002, there were 296,008 stock units outstanding.
25
Stock option activities under the FE Programs for the past three years
were as follows:
Number of Weighted Average
Stock Option Activities Options Exercise Price
- ------------------------------------------------------------------------------
Balance, January 1, 2000............... 2,153,369 $25.32
(159,755 options exercisable).......... 24.87
Options granted...................... 3,011,584 23.24
Options exercised.................... 90,491 26.00
Options forfeited.................... 52,600 22.20
Balance, December 31, 2000............ 5,021,862 24.09
(473,314 options exercisable).......... 24.11
Options granted...................... 4,240,273 28.11
Options exercised.................... 694,403 24.24
Options forfeited.................... 120,044 28.07
Balance, December 31, 2001............. 8,447,688 26.04
(1,828,341 options exercisable)........ 24.83
Options granted...................... 3,399,579 34.48
Options exercised.................... 1,018,852 23.56
Options forfeited.................... 392,929 28.19
Balance, December 31, 2002............ 10,435,486 28.95
(1,400,206 options exercisable)........ 26.07
As of December 31, 2002, the weighted average remaining contractual life
of outstanding stock options was 7.6 years.
No material stock-based employee compensation expense is reflected in
net income for stock options granted under the above plans since the exercise
price was equal to the market value of the underlying common stock on the grant
date. The effect of applying fair value accounting to FirstEnergy's stock
options is summarized in Note 1E - Stock-Based Compensation.
(C) PREFERRED AND PREFERENCE STOCK-
Preferred stock may be redeemed by the Company, in whole or in part,
with 30-90 days' notice.
(D) COMPANY-OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF
LIMITED PARTNERSHIP HOLDING SOLELY COMPANY SUBORDINATED DEBENTURES-
JCP&L Capital, L.P. is a special-purpose limited partnership in which a
subsidiary of the Company is the sole general partner. The limited partnership
invested the gross proceeds from the sale of $125.0 million at 8.56% of monthly
income preferred securities (MIPS) in $128.9 million of the Company's 8.56%
subordinated debentures. The sole assets of the limited partnership are these
subordinated debentures, which have the same rate and maturity date as the
preferred securities. The Company has effectively provided a full and
unconditional guarantee of its obligations under its limited partnership's MIPS,
to the extent that there is sufficient cash on hand to permit such payments and
funds legally available therefor, and payments on liquidation or redemption with
respect to the MIPS. Distributions on the limited partnership's MIPS (and
interest on the subordinated debentures) may be deferred for up to 60 months,
but the Company may not pay dividends on, or redeem or acquire, any of its
cumulative preferred or common stock until deferred payments on its subordinated
debentures are paid in full. The limited partnership's MIPS, which mature in
2044 and have a liquidation value of $25.00 per security, are redeemable at the
option of the Company at 100% of their principal amount.
26
(E) LONG-TERM DEBT-
The Company's first mortgage bond indenture, which secures all of the
Company's FMBs, serve as a direct first mortgage lien on substantially all of
the Company's property and franchises, other than specifically excepted
property.
The Company has various debt covenants under its financing arrangements.
The most restrictive of these relate to the nonpayment of interest and/or
principal on debt, which could trigger a default. Cross-default provisions also
exist between FirstEnergy and the Company.
Based on the amount of bonds authenticated by the Trustee through
December 31, 2002 the Company's annual improvement fund requirements for all
bonds issued under the mortgage amount to $15.7 million. The Company expects to
fulfill its improvement fund obligation by providing refundable bonds to the
Trustee.
Sinking fund requirements for FMBs and maturing long-term debt
(excluding capital leases) for the next five years are:
(In millions)
------------------------
2003........ $173.8
2004........ 175.9
2005........ 66.9
2006........ 230.6
2007........ 36.7
-------------------------
(F) SECURITIZED TRANSITION BONDS-
On June 11, 2002, JCP&L Transition Funding LLC (Issuer), a wholly owned
limited liability company of the Company, sold $320 million of transition bonds
to securitize the recovery of the Company's bondable stranded costs associated
with the previously divested Oyster Creek Nuclear Generating Station.
The Company does not own nor did it purchase any of the transition
bonds, which are included in long-term debt on and the Company's Consolidated
Balance Sheet. The transition bonds represent obligations only of the Issuer and
are collateralized solely by the equity and assets of the Issuer, which consist
primarily of bondable transition property. The bondable transition property is
solely the property of the Issuer.
Bondable transition property represents the irrevocable right of a
utility company to charge, collect and receive from its customers, through a
non-bypassable transition bond charge, the principal amount and interest on the
transition bonds and other fees and expenses associated with their issuance. The
Company, as servicer, manages and administers the bondable transition property,
including the billing, collection and remittance of the transition bond charge,
pursuant to a servicing agreement with the Issuer. The Company is entitled to a
quarterly servicing fee of $100,000 that is payable from transition bond charge
collections.
(G) COMPREHENSIVE INCOME-
Comprehensive income includes net income as reported on the Consolidated
Statements of Income and all other changes in common stockholder's equity except
those resulting from transactions with the Company's parent. As of December 31,
2002, accumulated other comprehensive loss consisted of unrealized losses on
derivative instrument hedges of $0.9 million.
5. SHORT-TERM BORROWINGS:
The Company may borrow from its affiliates on a short-term basis. As of
December 31, 2002, the Company had no short-term borrowings outstanding.
6. COMMITMENTS, GUARANTEES AND CONTINGENCIES:
(A) CAPITAL EXPENDITURES-
The Company's current forecast reflects expenditures of approximately
$462 million for property additions and improvements from 2003 through 2007, of
which approximately $102 million is applicable to 2003.
(B) NUCLEAR INSURANCE-
The Price-Anderson Act limits the public liability relative to a single
incident at a nuclear power plant to $9.5 billion. The amount is covered by a
combination of private insurance and an industry retrospective rating plan.
Based on
27
its present ownership interest in TMI-2, the Company is exempt from any
potential assessment under the industry retrospective rating plan.
The Company is also insured as to its interest in TMI-2 under a policy
issued to the operating company for the plant. Under this policy, $150 million
is provided for property damage and decontamination and decommissioning costs.
Under this policy, the Company can be assessed a maximum of approximately $0.2
million for incidents at any covered nuclear facility occurring during a policy
year which are in excess of accumulated funds available to the insurer for
paying losses.
The Company intends to maintain insurance against nuclear risks as
described above as long as it is available. To the extent that property damage,
decontamination, decommissioning, repair and replacement costs and other such
costs arising from a nuclear incident at TMI-2 exceed the policy limits of the
insurance in effect with respect to that plant, to the extent a nuclear incident
is determined not to be covered by the Company's insurance policies, or to the
extent such insurance becomes unavailable in the future, the Company would
remain at risk for such costs.
(C) ENVIRONMENTAL MATTERS-
The Company has been named as a "potentially responsible party" (PRP) at
waste disposal sites which may require cleanup under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980. Allegations of
disposal of hazardous substances at historical sites and the liability involved
are often unsubstantiated and subject to dispute; however, federal law provides
that all PRPs for a particular site be held liable on a joint and several basis.
Therefore, potential environmental liabilities have been recognized on the
Consolidated Balance Sheet as of December 31, 2002, based on estimates of the
total costs of cleanup, the Company's proportionate responsibility for such
costs and the financial ability of other nonaffiliated entities to pay. In
addition, the Company has accrued liabilities for environmental remediation of
former manufactured gas plants in New Jersey; those costs are being recovered
through a non-bypassable societal benefits charge. The Company has total accrued
liabilities aggregating approximately $47.1 million as of December 31, 2002. The
Company does not believe environmental remediation costs will have a material
adverse effect on its financial condition, cash flows or results of operations.
(D) OTHER LEGAL PROCEEDINGS-
Various lawsuits, claims and proceedings related to the Company's normal
business operations are pending against the Company, the most significant of
which are described below.
The Company has a 25% ownership interest in TMI-2, which was damaged
during a 1979 accident. As a result of the accident, claims for alleged personal
injury were filed against the Company, Met-Ed, Penelec and GPU (the defendants)
in the U.S. District Court for the Middle District of Pennsylvania. In 1996, the
District Court granted a motion for summary judgment filed by the defendants and
dismissed the ten initial "test cases" which had been selected for a test case
trial. In January 2002, the District Court granted the defendants' July 2001
motion for summary judgment on the remaining 2,100 pending claims. In February
2002, the plaintiffs filed a notice of appeal to the United States Court of
Appeals for the Third Circuit. In December 2002, the Court of Appeals refused to
hear the appeal, which effectively ended further legal action for those claims.
In July 1999, the Mid-Atlantic states experienced a severe heat storm
which resulted in power outages throughout the service territories of many
electric utilities, including the service territory of the Company. In an
investigation into the causes of the outages and the reliability of the
transmission and distribution systems of all four New Jersey electric utilities,
the NJBPU concluded that there was not a prima facie case demonstrating that,
overall, the Company provided unsafe, inadequate or improper service to its
customers. In July 1999, two class action lawsuits (subsequently consolidated
into a single proceeding) were filed in New Jersey Superior Court against the
Company and other GPU companies, seeking compensatory and punitive damages
arising from the July 1999 service interruptions in the Company's service
territory. In May 2001, the court denied without prejudice the Company's motion
seeking decertification of the class. Discovery continues in the class action,
but no trial date has been set. In October 2001, the court held argument on the
plaintiffs' motion for partial summary judgment, which contends that the Company
is bound to several findings of the NJBPU investigation. The plaintiffs' motion
was denied by the Court in November 2001 and the plaintiffs' motion to file an
appeal of this decision was denied by the New Jersey Appellate Division. The
Company has also filed a motion for partial summary judgment that is currently
pending before the Superior Court. The Company is unable to predict the outcome
of these matters.
28
7. OTHER INFORMATION:
The following represents the financial data which includes
supplemental unaudited prior years' information as compared to consolidated
financial statements and notes previously reported in 2001 and 2000.
(A) CONSOLIDATED STATEMENTS OF CASH FLOWS
Nov. 7- Jan. 1-
Dec. 31, Nov. 6,
2002 2001 2001 2002
---- ---- ---- ----
Other Cash Flows from Operating Activities:
Accrued taxes............................. $(21,939) $ 2,675 | $24,272 $ 4,242
Accrued interest.......................... 1,625 9,501 | (7,590) 898
Retail rate refunds obligation payments... (43,016) -- | -- --
Prepayments and other..................... (21,149) 16,436 | 63,909 (73,916)
All other................................. 66,837 (8,049) | (14,263) (161,324)
-------- -------- | ------- ---------
Other cash used for operating activities $(17,642) $20,563 | $66,328 $(230,100)
======== ======= | ======= =========
(B) REVENUES - INDEPENDENT SYSTEM OPERATOR (ISO) TRANSACTIONS
The Company records purchase and sales transactions with PJM
Interconnection ISO, an independent system operator, on a gross basis in
accordance with EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal
versus Net as an Agent." The aggregate purchase and sales transactions for the
three years ended December 31, 2002, are summarized as follows:
Nov. 7-Dec. 31, Jan. 1-Nov. 6,
2002 2001 2001 2000
-------------------------------------------------------
(In millions)
Sales..... $136 $ 2 | $ 28 $87
Purchases. 101 16 | 188 66
-------------------------------|-----------------------
The Company's revenues on the Consolidated Statements of Income include
wholesale electricity sales revenues from the PJM ISO from power sales (as
reflected in the table above) during periods when the Company had additional
available power capacity. Revenues also include sales by the Company of power
sourced from the PJM ISO (reflected as purchases in the table above) during
periods when the Company required additional power to meet its retail load
requirements.
(C) TRANSACTIONS WITH AFFILIATED COMPANIES-
The primary affiliated companies transactions are as follows:
Nov. 7- Jan. 1-
Dec. 31, Nov. 6,
2002 2001 2001 2000
- ------------------------------------------------------------------------------
(In millions)
Operating Revenues:
Wholesale sales-affiliated companies... $ 17.6 $ 2.4 | $17.3 $ 3.0
|
Operating Expenses: |
GPU Service, Inc. support services..... 140.4 21.0 | 120.0 259.0
Power purchased from other affiliates.. 26.1 3.4 | 16.1 48.1
Power purchased from FES............... 17.9 7.5 | -- --
- -----------------------------------------------------------------------------
(D) RETIREMENTS BENEFITS (1)
Net pension and other postretirement benefit costs (income) for the
three years ended December 31, 2002 are approximately as follows:
Nov. 7- Jan. 1-
Dec. 31, Nov. 6,
2002 2001 2001 2000
- ------------------------------------------------------------------------------
(In millions)
Pension Benefits....................... $(19.6) $(6.7) | $(33.4) $(10.6)
Other Postretirement Benefits.......... 5.3 1.7 | 8.3 14.9
- ------------------------------------------------------------------------------
(1) Includes estimated portion of benefit costs included in billings from GPUS.
29
8 . RECENTLY ISSUED ACCOUNTING STANDARDS:
FASB Interpretation (FIN) No. 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others - an interpretation of FASB Statements No. 5, 57,
and 107 and rescission of FASB Interpretation No. 34"
The FASB issued FIN 45 in January 2003. This interpretation identifies
minimum guarantee disclosures required for annual periods ending after December
15, 2002. It also clarifies that providers of guarantees must record the fair
value of those guarantees at their inception. This accounting guidance is
applicable on a prospective basis to guarantees issued or modified after
December 31, 2002. The Company does not believe that implementation of FIN 45
will be material but it will continue to evaluate anticipated guarantees.
FIN 46, "Consolidation of Variable Interest Entities - an interpretation
of ARB 51"
In January 2003, the FASB issued this interpretation of ARB No. 51,
"Consolidated Financial Statements". The new interpretation provides guidance on
consolidation of variable interest entities (VIEs), generally defined as certain
entities in which equity investors do not have the characteristics of a
controlling financial interest or do not have sufficient equity at risk for the
entity to finance its activities without additional subordinated financial
support from other parties. This interpretation requires an enterprise to
disclose the nature of its involvement with a VIE if the enterprise has a
significant variable interest in the VIE and to consolidate a VIE if the
enterprise is the primary beneficiary. VIEs created after January 31, 2003 are
immediately subject to the provisions of FIN 46. VIEs created before February 1,
2003 are subject to this interpretation's provisions in the first interim or
annual reporting period beginning after June 15, 2003 (our third quarter of
2003). The FASB also identified transitional disclosure provisions for all
financial statements issued after January 31, 2003.
The Company currently has transactions with entities in connection with
the sale of preferred securities, which may fall within the scope of this
interpretation, and which are reasonably possible of meeting the definition of a
VIE in accordance with FIN 46. The Company currently consolidates these entities
and believes it will continue to consolidate following the adoption of FIN 46.
9. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):
The following summarizes certain consolidated operating results by
quarter for 2002 and 2001.
March 31, June 30, September 30, December 31,
Three Months Ended 2002 2002 2002 2002
- -------------------------------------------------------------------------------------------------------------
(In millions)
Operating Revenues.......................... $450.7 $501.3 $779.9 $596.5
Operating Expenses and Taxes................ 389.4 423.1 658.6 522.1
- -------------------------------------------------------------------------------------------------------------
Operating Income............................ 61.3 78.2 121.3 74.4
Other Income ............................... 2.8 2.2 1.2 1.5
Net Interest Charges........................ 24.1 23.0 21.8 22.1
- -------------------------------------------------------------------------------------------------------------
Net Income.................................. $ 40.0 $ 57.4 $100.7 $ 53.8
=============================================================================================================
Earnings on Common Stock.................... $ 39.2 $ 57.0 $103.5 $ 53.7
=============================================================================================================
Three Months Ended
------------------------------------
March 31, June 30, Sept. 30, Oct. 1-Nov. 6, Nov. 7-Dec. 31,
2001 2001 2001 2001 2001
- ----------------------------------------------------------------------------------------------------------------------
(In millions)
Operating Revenues.......................... $461.7 $521.0 $672.2 $ 183.7 | $282.9
Operating Expenses and Taxes................ 388.2 451.7 554.0 151.9 | 239.2
- -------------------------------------------------------------------------------------------------------|--------------
Operating Income............................ 73.5 69.3 118.2 31.8 | 43.7
Other Income (Expense)...................... 1.2 2.3 (2.7) (177.7) | 1.2
Net Interest Charges........................ 23.3 25.6 24.3 8.3 | 14.8
- -------------------------------------------------------------------------------------------------------|--------------
Net Income (Loss)........................... $ 51.4 $ 46.0 $ 91.2 $(154.2) | $ 30.1
=======================================================================================================|==============
Earnings (Loss) on Common Stock............. $ 50.0 $ 44.7 $ 89.8 $(154.5) | $ 29.3
======================================================================================================================
30
Report of Independent Accountants
To the Stockholders and Board of Directors of
Jersey Central Power & Light Company:
In our opinion, the accompanying consolidated balance sheet and consolidated
statement of capitalization and the related consolidated statements of income,
common stockholder's equity, preferred stock, cash flows and taxes present
fairly, in all material respects, the financial position of Jersey Central Power
& Light Company (a wholly owned subsidiary of FirstEnergy Corp.) and
subsidiaries as of December 31, 2002, and the results of their operations and
their cash flows for the year then ended and the year ended December 31, 2000
(pre-merger) in conformity with accounting principles generally accepted in the
United States of America. These financial statements are the responsibility of
the Company's management; our responsibility is to express an opinion on these
financial statements based on our audit. We conducted our audits of these
statements in accordance with auditing standards generally accepted in the
United States of America, which require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion. The consolidated financial
statements of Jersey Central Power & Light Company and subsidiaries as of
December 31, 2001 and for the period from January 1, 2001 to November 6, 2001
(pre-merger) and the period from November 7, 2001 to December 31, 2001
(post-merger) were audited by other independent accountants who have ceased
operations. Those independent accountants expressed an unqualified opinion on
those financials statements in their report dated March 18, 2002.
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 28, 2003
31
The following report is a copy of a report previously issued by Arthur Andersen
LLP and has not been reissued by Arthur Andersen LLP.
Report of Previous Independent Public Accountants
To the Stockholders and Board of Directors of
Jersey Central Power & Light Company:
We have audited the accompanying consolidated balance sheet and consolidated
statement of capitalization of Jersey Central Power & Light Company (a New
Jersey corporation and wholly owned subsidiary of FirstEnergy Corp.) and
subsidiaries as of December 31, 2001 (post-merger), and the related consolidated
statements of income, common stockholder's equity, preferred stock, cash flows
and taxes for the period from January 1, 2001 to November 6, 2001 (pre-merger)
and the period from November 7, 2001 to December 31, 2001 (post-merger). These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audit. The financial statements of Jersey Central Power & Light Company and
subsidiary as of December 31, 2000 and for each of the two years in the period
ended December 31, 2000 (pre-merger), were audited by other auditors whose
report dated January 31, 2001, expressed an unqualified opinion on those
statements.
We conducted our audit in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audit provides a reasonable basis for our
opinion.
In our opinion, the 2001 financial statements referred to above present fairly,
in all material respects, the financial position of Jersey Central Power & Light
Company and subsidiaries as of December 31, 2001 (post-merger), and the results
of their operations and their cash flows for the period from January 1, 2001 to
November 6, 2001 (pre-merger) and the period from November 7, 2001 to December
31, 2001 (post-merger), in conformity with accounting principles generally
accepted in the United States.
ARTHUR ANDERSEN LLP
Cleveland, Ohio,
March 18, 2002.
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